
Aligning Utility Incentives 


with Investment in 
Energy Efficiency 

A RESOURCE OF THE NATIONAL ACTION PLAN FOR 
ENERGY EFFICIENCY 


NOVEMBER 2007 





















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This report on Aligning Utility Incentives with Investment in Energy 
Efficiency is provided to assist gas and electric utilities, utility regu¬ 
lators, and others in the implementation of the recommendations 
of the National Action Plan for Energy Efficiency (Action Plan) and 
the pursuit of its longer-term goals. 


The Report describes the financial effects on a utility of its spend¬ 
ing on energy efficiency programs, how those effects could consti¬ 
tute barriers to more aggressive and sustained, utility investment in 
energy efficiency, and how adoption of various policy mechanisms 
can reduce or eliminate these barriers. The Report also provides a 
number of examples of such mechanisms drawn from the experi¬ 
ence of utilities and states. 


The primary intended audiern this paper are utilities, state 


policy-makers, and energy 
ic options for addressing th 


in energy efficiency. 



vocates interested in specif- 
arriers to utility investment 
















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Aligning Utility Incentives 
with Investment in Energy 

Efficiency 


A RESOURCE OF THE NATIONAL ACTION PLAN FOR 

ENERGY EFFICIENCY 


NOVEMBER 2007 








I 


Aligning Utility Incentives with Investment in Energy Efficiency is a product of the National Action Plan for Energy Effi¬ 
ciency Leadership Group and does not reflect the views, policies, or otherwise of the federal government. The role of the 
U.S. Department of Energy and U.S. Environmental Protection Agency is limited to facilitation of the Action Plan. 

This document was final as of December 2007 and incorporates minor modifications to the original release. 

If this document is referenced, it should be cited as: 

National Action Plan for Energy Efficiency (2007). Aligning Utility Incentives with Investment in Energy Efficiency. Pre¬ 
pared by Val R. Jensen, ICF International, <www.epa.gov/eeactionplan> 


For More Information 


Regarding Aligning Utility Incentives with Investment in Energy Efficiency, please contact: 

\ 

Joe Bryson 

U.S. Environmental Protection Agency 
Office of Air and Radiation 

si y o 

Climate Protection Partnerships Division 
Tel: (202) 343-9631 
E-mail: bryson.joe@epa.gov 

Regarding the National Action Plan for Energy Efficiency, please contact: 


Stacy Angel 

U.S. Environmental Protection Agency 

Office of Air and Radiation 

Climate Protection Partnerships Division 

Tel: (202) 343-9606 

E-mail: angel.stacy@epa.gov 


Larry Mansueti 

U.S. Department of Energy 

Office of Electricity Delivery and Energy Reliability 

Tel: (202) 586-2588 

E-mail: lawrence.mansueti@hq.doe.gov 


or visit www.epa.gov/eeactionplan 




Table of Contents 


List of Figures. 

List of Tables. 

List of Abbreviations and Acronyms. 

Acknowledgements. 

Executive Summary. 

The Financial and Policy Context. 

Program Cost Recovery. 

Lost Margin Recovery and the Throughput Incentive. 

Utility Performance Incentives. 

Understanding Objectives—Developing Policy Approaches That Fit... 

Emerging Models. 

Final Thoughts. 

Notes. 

Chapter 1: Introduction. 

1.1 Energy Efficiency Investment. 

1.2 Aligning Utility Incentives with Investment in Energy Efficiency Report. 

1.3 Notes. 1 . 

Chapter 2: The Financial and Policy Context for Utility Investment in Energy Efficiency 

2.1 Overview. 

2.2 Program Cost Recovery. 

2.3 Lost Margin Recovery.. 

2.4 Performance Incentives. 

2.5 Linking the Mechanisms. 

2.6 "The DNA of the Company:" Examining the Impacts of Effective Mechanisms on the 

Corporate Culture. 

2.7 The Cost of Regulatory Risk. 

2.8 Notes. 

Chapter 3: Understanding Objectives—Developing Policy Approaches That Fit. 

3.1 Potential Design Objectives. 

3.2 The Design Context. 

3.3 Notes. 


.ii 

.iii 

.v 

ES-1 

ES-1 

ES-2 

ES-2 

ES-3 

ES-4 

ES-7 

ES-7 

ES-8 

.. 1-1 

.. 1-1 

.. 1-8 

1-10 

..2-1 

.. 2-1 

.. 2-2 

..2-3 

..2-7 

.. 2-8 


..2-9 

2-10 

2-11 


3-1 

3-1 


3-3 

3-5 


National Action Plan for Energy Efficiency 








































Table of Contents (continued) 

Chapter 4: Program Cost Recovery.4-1 

4.1 Overview.:.4-1 

4.2 Expensing of Energy Efficiency Program Costs.4-1 

4.3 Capitalization and Amortization of Energy Efficiency Program Costs.4-5 

4.4 Notes. 4-9 

Chapter 5: Lost Margin Recovery.5-1 

5.1 Overview ..5-1 

5.2 Decoupling.5-1 

5.3 Lost Revenue Recovery Mechanisms.5-10 

5.4 Alternative Rate Structures.5-12 

5.5 Notes. 5-13 

Chapter 6: Performance Incentives.6-1 

6.1 Overview.:.6-1 

6.2 Performance Targets.6-3 

6.3 Shared Savings.6-4 

6.4 Enhanced Rate of Return.6-11 

6.5 Pros and Cons of Utility Performance Incentive Mechanisms.6-11 

6.6 Notes.6-12 

Chapter 7: Emerging Models.7-1 

7.1 Introduction.7-1 

7.2 Duke Energy's Proposed Save-a-Watt Model.7-1 

7.3 ISO New England's Market-Based Approach to Energy Efficiency Procurement.7-4 

7.4 Notes.7-5 

Chapter 8: Final Thoughts—Getting Started.8-1 

8.1 Lessons for Policy-Makers.8-1 

Appendix A: National Action Plan for Energy Efficiency Leadership Group.Appendix A-1 

Appendix B: Glossary.Appendix B-1 

Appendix C: Sources for Policy Status Table.Appendix C-1 

Appendix D: Case Study Detail.Appendix D-1 

Appendix E: References.Appendix E-1 


Aligning Utility Incentives with Investment in Energy Efficiency 


































List of Figures 


Figure ES-1. Cost Recovery and Performance Incentive Options.ES-2 

Figure 1-1. Annual Utility Spending on Electric Energy Efficiency.1-1 

/ 

Figure 1-2. National Action Plan for Energy Efficiency Recommendations and Options.1-2 

Figure 2-1. Linking Cost Recovery, Recovery of Lost Margins, and Performance Incentives.2-9 

Figure 6-1. California Performance Incentive Mechanism Earnings/Penalty Curve.6-9 


National Action Plan for Energy Efficiency 















List of Tables 


Table ES-1. The Status of Energy Efficiency Cost Recovery and Incentive Mechanisms for 

Investor-Owned Utilities.ES-5 

Table 1-1. Utility Financial Concerns.1-3 

Table 1-2. The Status of Energy Efficiency Cost Recovery and Incentive Mechanisms for 

Investor-Owned Utilities.1-6 

Table 2-1. The Arithmetic of Rate-Setting.2-5 

Table 3-1. Cost Recovery and Incentive Design Considerations.3-3 

Table 4-1. Pros and Cons of Expensing Program Costs....4-3 

Table 4-2. Current Cost Recovery Factors in Florida.4-4 

Table 4-3. Illustration of Energy Efficiency Investment Capitalization.4-6 

Table 4-4. Pros and Cons of Capitalization and Amortization.4-8 

Table 5-1. Illustration of Revenue Decoupling.........5-2 

Table 5-2. Illustration of Revenue per Customer Decoupling.5-3 

Table 5-3. Pros and Cons of Revenue Decoupling.5-5 

Table 5-4. Questar Gas DNG Revenue per Customer per Month.5-9 

Table 5-5. Pros and Cons of Lost Revenue Recovery Mechanisms.5-11 

Table 5-6. Louisville Gas and Electric Company DSM Cost Recovery Rates.5-12 

Table 5-7. Pros and Cons of Alternative Rate Structures.5-13 

Table 6-1. Examples of Utility Performance Incentive Mechanisms.6-1 

Table 6-2. Northern States Power Net Benefit Calculation.6-6 

Table 6-3. Northern States Power 2007 Electric Incentive Calculation.6-6 

Table 6-4. Hawaiian Electric Company Shared Savings Incentive Structure.6-7 

Table 6-5. Illustration of HECO Shared Savings Calculation.6-8 

Table 6-6. Ratepayer and Shareholder Benefits Under California's Shareholder Incentive Mechanism 

(Based on 2006-2008 Program Cycle Estimates).6-10 

Table 6-7. Pros and Cons of Utility Performance Incentive Mechanisms.6-12 


ii 


Guide to Resource Planning with Energy Efficiency 




























List of Abbreviations and Acronyms 


A 


E 

APS 

Arizona Public Service Company 

ECCR 

B 


EPA 

BA 

balance adjustment 

ER 

BGE 

Baltimore Gas & Electric 

ERAM 

BGSS 

Basic Gas Supply Service 

F 

c 


FCA 

CCRA 

conservation cost recovery adjustment 

FCM 

CCRC 

conservation cost recovery charge 

FEECA 

CET 

conservation enabling tariff 

FPL 

CIP 

conservation improvement program or 
Conservation Incentive Program 

H 

CMP 

Central Maine Power 

HECO 

CPUC 

California Public Utilities Commission 

I 

ISO 

CUA 

conservation and usage adjustment 

D 


K 

kW 

DBA 

DSM balance adjustment 

DCR 

DSM program cost recovery 

kWh 

DNG 

distribution non-gas 


DOE 

U.S. Department of Energy 

L 

DRLS 

DSM revenue from lost sales 

LG&E 

DSM 

demand-side management 

LRAM 

DSMI 

DSM incentive 

M 

DSMRC 

demand-side management recovery 

MW 


component 

MWh 


I 


energy conservation cost recovery 
U.S. Environmental Protection Agency 
earnings rate 

electric rate adjustment mechanism 


fixed cost adjustment 

forward capacity market 

Florida Energy Efficiency and 
Conservation Act 

Florida Power and Light 


Hawaiian Electric Company 


independent system operator 


kilowatt 

kilowatt-hour 


Louisville Gas & Electric 

lost revenue adjustment mechanism 


megawatt 

megawatt-hour 


National Action Plan for Energy Efficiency 


hi 























List of Abbreviations and Acronyms (continued) 


N 


NARUC 

National Association of Regulatory Utility 
Commissioners 

NJNG 

New Jersey Natural Gas 

NJR 

New Jersey Resources 

NJRES 

NJR Energy Services 

NSP 

Northern States Power Company 

0 

O&M 

operation and maintenance 

p 

PBR 

performance-based ratemaking 

PEB 

performance earnings basis 

PG&E 

Pacific Gas & Electric Company 


R 


RAP 

ROE 

s 

Regulatory Assistance Project 

return on equity 


SFV 

Straight Fixed-Variable 


SJG 

South Jersey Gas 


u 



UCE 

Utah Clean Energy 



IV 


Guide to Resource Planning with Energy Efficiency 









Acknowledgements 


This report on Aligning Utility Incentives with Invest¬ 
ment in Energy Efficiency is a key product of the Year 
Two Work Plan for the National Action Plan for Energy 
Efficiency. This work plan was developed based on 
feedback received from Action Plan Leadership Group 
members and observers during fall 2006. The work plan 
was further refined during the March 2007 Leadership 
Group meeting in Washington, D.C. A full list of Leader¬ 
ship Group members is provided in Appendix A. 

In addition to direction and comment by the Action Plan 
Leadership Group, this Report was prepared with highly 
valuable input of an Advisory Group. Val Jensen of ICF 
International served as project manager and primary 
author of the Report, with assistance from Basak Uluca, 
under contract to the U.S. Environmental Protection 
Agency (EPA). 

The Advisory Group members are: 

• Lynn Anderson, Idaho Public Service Commission 

• Jeff Burks, PNM Resources 

• Sheryl Carter, Natural Resources Defense Council 

• Dan Cleverdon, DC Public Service Commission 

• Roger Duncan, Austin Energy 

• Jim Gallagher, New York State Public Service 
Commission 

• Marty Haught, United Cooperative Service 

• Leonard Haynes, Southern Company 


• Mark McGahey, Tristate Generation and 
Transmission Association, Inc. 

• Barrie McKay, Questar Gas Company 

• Roland Risser, Pacific Gas & Electric 

• Gene Rodrigues, Southern California Edison 

• Michael Shore, Environmental Defense 

• Raiford Smith, Duke Energy 

• Henry Yoshimura, ISO New England Inc. 

Rich Sedano of the Regulatory Assistance Project (RAP) 
and Alison Silverstein of Alison Silverstein Consulting 
provided their expertise during review and editing of 
the Report. 

The U.S. Department of Energy (DOE) and EPA facilitate 
the National Action Plan for Energy Efficiency, including 
this Report. Key staff include Larry Mansueti with DOE'S 
Office of Electricity Delivery and Energy Reliability; Dan 
Beckley with DOE'S Office of Energy Efficiency and Re¬ 
newable Energy; and Kathleen Hogan, Joe Bryson, Stacy 
Angel, and Katrina Pielli with EPA's Climate Protection 
Partnerships Division. 

Eastern Research Group, Inc., provided technical review, 
copyediting, graphics, and production services. 


Mary Healey, Connecticut Office of 
Consumer Counsel 

Denise Jordan, Tampa Electric Company 
Don Low, Kansas Corporation Commission 


National Action Plan for Energy Efficiency 


v 















Executive Summary 



This report on Aligning Utility Incentives with Investment in Energy Efficiency describes the financial 
effects on a utility of its spending on energy efficiency programs, how those effects could constitute 
barriers to more aggressive and sustained utility investment in energy efficiency, and how adoption of 
various policy mechanisms can reduce or eliminate these barriers. The Report also provides a number of 
examples of such mechanisms drawn from the experience of utilities and states. The Report is provided 
to assist in the implementation of the National Action Plan for Energy Efficiency's five key policy recom¬ 
mendations for creating a sustainable, aggressive national commitment to energy efficiency. 


Improving energy efficiency in our homes, businesses, 
schools, governments, and industries—which collec¬ 
tively consume more than 70 percent of the natural 
gas and electricity used in the country—is one of the 
most constructive, cost-effective ways to address the 
challenges of high energy prices, energy security and 
independence, air pollution, and global climate change. 
Despite these benefits and the success of energy effi¬ 
ciency programs in some regions of the country, energy 
efficiency remains critically underutilized in the nation's 
energy portfolio. It is time to take advantage of more 
than two decades of experience with successful energy 
efficiency programs, broaden and expand these efforts, 
and capture the savings that energy efficiency offers. 
Aligning the financial incentives of utilities with the 
delivery of cost-effective energy efficiency supports the 
key role utilities can play in capturing energy savings. 

This Report has been developed to help parties fully 
implement the five key policy recommendations of the 
National Action Plan for Energy Efficiency. (See Figure 
1-1 for a full list of options to consider under each 
Action Plan recommendation.) The Action Plan was 
released in July 2006 as a call to action to bring diverse 
stakeholders together at the national, regional, state, or 
utility level, as appropriate, and foster the discussions, 
decision-making, and commitments necessary to take 
investment in energy efficiency to a new level. 

This Report directly supports the Action Plan recom¬ 
mendations to "provide sufficient, timely, and stable 


program funding to deliver energy efficiency where 
cost-effective" and "modify policies to align utility 
incentives with the delivery of cost-effective energy 
efficiency and modify ratemaking practices to promote 
energy efficiency investments." Key options to consider 
under this recommendation include committing to a 
consistent way to recover costs in a timely manner, 
addressing the typical utility throughput incentive and 
providing utility incentives for the successful manage¬ 
ment of energy efficiency programs. 

There are a number of possible regulatory mechanisms 
for addressing these issues. Determining which mecha¬ 
nism will work best for any given jurisdiction is a process 
that takes into account the type and financial structure 
of the utilities in that jurisdiction; existing statutory and 
regulatory authority; and the size of the energy efficien¬ 
cy investment. The net impact of an energy efficiency 
cost recovery and performance incentives policy will 
be affected by a wide variety of other rate design, cost 
recovery, and resource procurement strategies, as well 
as broader considerations, such as the rate of demand 
growth and environmental and resource policies. 

The Financial and Policy Context 

Utility spending on energy efficiency programs can 
affect the utility's financial position in three ways: (1) 
through recovery of the direct costs of the programs; 

(2) through the impact on utility earnings of reduced 


National Action Plan for Energy Efficiency 


ES-1 



sales; and (3) through the effects on shareholder value 
of energy efficiency spending versus investment in 
supply-side resources. The relative importance of each 
effect to a utility is measured by its impact on earnings 
A variety of mechanisms have been developed to ad¬ 
dress these impacts, as illustrated in Figure ES-1. 


Figure ES-1. Cost Recovery and 
Performance Incentive Options 


Expense Lost revenue 

Rate case adjustment 

rider mechanism 



(LRAM) 


Lost margin 
recovery 


Program cost 
recovery 


Performance 

incentives 


Capitalize 


Rate case 
deferral 

Performance 

payment 


Decoupling 
Shared savings 
ROR adder 


Program Cost Recovery 

The most immediate impact is that of the direct costs 
associated with program administration (including 
evaluation), implementation, and incentives to program 
participants. Reasonable opportunity for program cost 
recovery is a necessary condition for utility program 
spending, as failure to recover these costs produces a 
direct dollar-for-dollar reduction in utility earnings, all 
else being equal, and sends a discouraging message 
regarding further investment. 

Policy-makers have a wide variety of tools available to 
them within the broad categories of expensing and cap¬ 
italization to address cost recovery. Program costs can 
be recovered as expenses or can be treated like capital 
items by accruing program costs with carrying charges, 
and then amortizing the balances with recovery over a 
period of years. Chapter 4 reviews both general options 
as well as several approaches for the tracking, accrual, 
and recovery of program costs. Case studies for Arizo¬ 
na, Iowa, Florida, and Nevada are presented to illustrate 
the actual application of the mechanisms. 


How these impacts are addressed creates the incentives 
and disincentives for utilities to pursue energy efficiency 
investment. The relative importance of each of these 
depends on specific context—the impacts of energy ef¬ 
ficiency programs will look different to gas and electric 
utilities, and to investor-owned, publicly owned, and 
cooperatively owned utilities. Comprehensive poli¬ 
cies addressing all three levels of impact generally are 
considered more effective in spurring utilities to pursue 
efficiency aggressively. Ultimately, however, it is the cu¬ 
mulative net effect on utility earnings or net income of a 
policy that will determine the alignment of utility finan¬ 
cial interests with energy efficiency investment. The same 
effect can be achieved in different ways, not all of which 
will include explicit mechanisms for each level. Chapter 2 
of this Report explores the financial effects of and policy 
issues associated with utility energy efficiency spending. 


Each of these tools can have different financial impacts, 
but the key factors in any case are the determination of 
the prudence of program expenditures and the timing 
of cost recovery. How each of these is addressed will af¬ 
fect the perceived financial risk of the policy. The more 
uncertain the process for determining the prudence 
of expenditures, and the longer the time between an 
expenditure and its recovery, the greater the perceived 
financial risk and the less likely a utility will be to ag¬ 
gressively pursue energy efficiency. 

Lost Margin Recovery and the 
Throughput Incentive 

The second impact, sometimes called the lost margin 
recovery issue is the effect on utility financial margins 
caused by the energy efficiency-produced drop in 
sales. Utilities incur both fixed and variable costs. Fixed 
costs include a return of (depreciation) and a return on 


ES-2 


Aligning Utility Incentives with Investment in Energy Efficiency 



(interest plus earnings) capital (a utility's physical infra¬ 
structure), as well as property taxes and certain opera¬ 
tion and maintenance (O&M) costs. These costs do not 
vary as a function of sales in the short-run. However, 
most utility rate designs attempt to recover a portion 
of these fixed costs through volumetric prices—a price 
per kilowatt-hour or per therm. These prices are based 
on an estimate of sales: price = revenue requirement/ 
sales. 1 If actual sales are either higher or lower than 
the level estimated when prices are set, revenues will 
be higher or lower. All else being equal, if an energy 
efficiency program reduces sales, it reduces revenues 
proportionately, but fixed costs do not change. Less 
revenue, therefore, means that the utility is at some 
risk for not recovering all of its fixed costs. Ultimately, 
the drop in revenue will impact the utility's earnings for 
an investor-owned utility, or net operating margin for 
publicly and cooperatively owned utilities. 

Few energy efficiency policy issues have generated as 
much debate as the issue of the impact of energy ef¬ 
ficiency programs on utility margins. Arguments on all 
sides of the lost margin issue can be compelling. Many 
observers would agree that significant and sustained 
investment in energy efficiency by utilities, beyond that 
required under statute or order, will not occur without 
implementation of some type of mechanism to ensure 
recovery of lost margins. Others argue that the lost mar¬ 
gin issue cannot be treated in isolation; margin recov¬ 
ery is affected by a wide variety of factors, and special 
adjustments for energy efficiency constitute single issue 
ratemaking. 2 

Care should be taken to ensure that two very different 
issues are not incorrectly treated as one. The first is¬ 
sue is whether a utility should be compensated for the 
under-recovery of fixed costs when energy efficiency 
programs or events outside of the control of the util¬ 
ity (e.g., weather or a drop in economic activity) reduce 
sales below the level on which current rates are based. 
Lost revenue adjustment mechanisms (LRAMs) have been 
designed to estimate and collect the margin revenues 
that might be lost due to a successful energy efficiency 
program. These mechanisms compensate utilities for the 
effect of reduced sales due to efficiency, but they do not 


change the linkage between sales and profit. Few states 
currently use these mechanisms. 

The second issue is whether potential lost margins should 
be addressed as a stand-alone matter of cost recovery or 
by decoupling revenues from sales—an approach that 
fundamentally changes the relationship between sales 
and revenues, and thus margins. Decoupling not only 
addresses lost margin recovery, but also removes the 
throughput incentive—the incentive for utilities to pro¬ 
mote sales growth, which is created when fixed costs are 
recovered through volumetric charges. The throughput 
incentive has been identified by many as the primary bar¬ 
rier to aggressive utility investment in energy efficiency. 

Chapter 5 examines the cause of and options for recov¬ 
ery of lost margins, and case studies are presented for 
decoupling in Idaho, New Jersey, Maryland, and Utah, 
and for the application of a LRAM in Kentucky. 

Utility Performance Incentives 

The two impacts described above pertain to potential 
direct disincentives for utilities to engage in energy ef¬ 
ficiency program investment. The third impact concerns 
incentives for utilities to undertake such investment. Un¬ 
der traditional regulation, investor-owned utilities earn 
returns on capital invested in generation, transmission, 
and distribution. Unless given the opportunity to profit 
from the energy efficiency investment that is intended 
to substitute for this capital investment, there is a clear 
financial incentive to prefer investment in supply-side 
assets, since these investments contribute to enhanced 
shareholder value. Providing financial incentives to a 
utility if it performs well in delivering energy efficiency 
can change that business model by making efficiency 
profitable rather than merely a break-even activity. 

The three major types of performance mechanisms have 
been most prevalent include: 

• Performance target incentives. 

• Shared savings incentives. 

• Rate of return adders. 


National Action Plan for Energy Efficiency 


ES-3 





Performance target incentives provide payment—often 
a percentage of the total program budget—for achieve¬ 
ment of specific metrics, usually including savings 
targets. Most states providing such incentives set per¬ 
formance ranges; incentives are not paid unless a utility 
achieves some minimum fraction of proposed savings, 
and incentives are capped at some level above projected 
savings. 

Shared savings mechanisms provide utilities the oppor¬ 
tunity to share with ratepayers the net benefits resulting 
from successful implementation of energy efficiency 
programs. These structures also include specific perfor¬ 
mance targets that tie the percentage of net savings 
awarded to the percentage of goal achieved. Some, 
but not all, shared savings mechanisms include penalty 
provisions requiring utilities to pay customers when 
minimum performance targets are not achieved. 

Rate of return adders provide an increase in the return 
on equity (ROE) applied to capitalized energy efficiency 
expenditures. This approach currently is not common as 
a performance incentive for several reasons. First, this 
mechanism requires energy efficiency program costs to 
be capitalized, which relatively few utilities prefer. Sec¬ 
ond, at least as applied in several cases, the adder is not 
tied to performance—it simply is applied to all capital¬ 
ized energy efficiency costs as a way to broadly incent 
a utility for efficiency spending. On the other hand, 
capitalization, in theory, places energy efficiency on 
more equal financial terms with supply-side investments 
to begin with. Thus, any adder could be viewed more as 
a risk-premium for investment in a regulatory asset. 

The premise that utilities should be paid incentives as 
a condition for effective delivery of energy efficiency 
programs is not universally accepted. Some argue that 
utilities are obligated to pursue energy efficiency if that 
is the policy of a state, and that performance incen¬ 
tives require customers to pay utilities to do something 
that they should do anyway. Others have argued more 
directly that the basic business of a utility is to deliver 
energy, and that providing financial incentives over-and- 
above what could be earned by efficient management 
of the supply business simply raises the cost of service 
to all customers and distorts management behavior. 


Chapter 6 reviews these mechanisms in greater detail 
and provides case studies drawn from Massachusetts, 
Minnesota, Hawaii, and California. 

Table ES-1 summarizes the current level of state activity 
with regard to the financial mechanisms describe above. 

Understanding Objectives— 
Developing Policy Approaches 
That Fit 

The overarching goal in every jurisdiction that considers 
an energy efficiency investment policy is to generate and 
capture substantial net economic benefits. Achieving 
this goal requires aligning utility financial interests with 
investment in energy efficiency. The right combination of 
cost recovery and performance incentive mechanisms to 
support this alignment requires a balancing of a variety of 
more specific objectives common to the ratemaking pro¬ 
cess. Chapter 3 reviews how these objectives might influ¬ 
ence design of a cost recovery and performance incentive 
policy, and highlights elements of the policy context that 
will affect policy design. Each of these objectives are not 
given equal weight by policy-makers, but most are given 
at least some consideration in virtually every discussion of 
cost recovery and performance incentives. 

• Strike an Appropriate Balance of Risk/Reward Be¬ 
tween Utilities/Customers. If a mechanism is well- 
designed and implemented, customer benefits will be 
large enough to allow sharing some of this benefit 

as a way to reduce utility risk and strengthen institu¬ 
tional commitment; all parties will be better off than 
if no investment had been made. 

• Promote Stabilization of Customer Rates and Bills. 
While it is prudent to explore policy designs that, 
among available options, minimize potential rate 
volatility, the pursuit of rate stability should be bal¬ 
anced against the broader interest of lowering the 
overall cost of providing electricity and natural gas. 

• Stabilize Utility Revenues. Even if post recovery 
policy covers program costs, fixed cost recovery and 
performance incentives, how this recovery takes 


ES-4 


Aligning Utility Incentives with Investment in Energy Efficiency 




Table ES-1. The Status of Energy Efficiency Cost Recovery and Incentive 
Mechanisms for Investor-Owned Utilities 

State 

Direct Cost Recovery 

Fixed Cost Recovery 

Performance 

Incentives 

Rate 

Case 

System 

Benefits 

Charge 

Tariff Rider/ 
Surcharge 

Decoupling 

Lost Revenue 
Adjustment 
Mechanism 

Alabama 

Yes 






Alaska 







Arizona 

Yes (electric) 

Yes (electric) 


Pending (gas) 


Yes (electric) 

Arkansas 




Yes (gas) 



California 

Yes 

Yes 


Yes 


Yes 

Colorado 

Yes 


Yes 

Pending 


Yes 

Connecticut 


Yes (electric) 



Yes 

Yes 

Delaware 

Yes 



Pending 



District of 

Columbia 

Yes 



Pending 

(electric) 



Florida 



Yes (electric) 




Georgia 

Yes 





Yes (electric) 

Hawaii 




Pending 

(electric) 

• 

Yes 

Idaho 

Yes (electric) 



Yes (electric) 



Illinois 

Yes (electric) 






Indiana 

Yes 



Yes (gas) 

Yes 

Yes 

Iowa 

Yes 


Yes 




Kansas 






Yes 

Kentucky 



Yes 

Pending (gas) 

Yes 

Yes 

Louisiana 







Maine 


Yes (electric) 





Maryland 

i 



Yes (gas) 
Pending 
(electric) 



Massachusetts 


Yes (electric) 


Pending 

(electric) 

Yes 

Yes (electric) 

Michigan 




Pending (gas) 



Minnesota 

Yes 



Yes 


Yes 

Mississippi 

Yes 






Missouri 




Yes (gas) 



Montana 

Yes (gas) 

Yes (electric) 




Yes 

Nebraska 







Nevada 

Yes (electric) 



Yes (gas) 


Yes (electric) 

New Hampshire 


Yes (electric) 


Pending 

(electric) 


Yes (electric) 


National Action Plan for Energy Efficiency 


ES-5 

























































Table ES-1. The Status of Energy Efficiency Cost Recovery and Incentive 
Mechanisms for Investor-Owned Utilities (continued) 

State 

Direct Cost Recovery 

Fixed Cost Recovery 

Performance 

Incentives 

Rate 

Case 

System 

Benefits 

Charge 

Tariff Rider/ 
Surcharge 

Decoupling 

Lost Revenue 
Adjustment 
Mechanism 

New Jersey 


Yes 


Yes (gas) 
Pending 
(electric) 



New Mexico 

Yes 



Pending (gas) 



New York 

P 

Yes (electric) 


Yes 



North Carolina 




Yes (gas) 



North Dakota 







Ohio 



Yes (electric) 

Yes (gas) 

Yes (electric) 

Yes (electric) 

Oklahoma 







Oregon 


Yes 


Yes (gas) 



Pennsylvania 

Yes 






Rhode Island 


Yes (electric) 


Yes 


Yes 

South Carolina 






Yes 

South Dakota 







Tennessee 







Texas 

Yes 






Utah 

Yes (electric) 


Yes (electric) 

Yes (gas) 



Vermont 


Yes (electric) 



Yes 

Yes 

Virginia 




Pending (gas) 



Washington 

Yes (electric) 


Yes (electric) 

Yes (gas) 



West Virginia 







Wisconsin 

Yes (electric) 

Yes (electric) 


Pending 

(electric) 



Wyoming 








Source: Kushler et al., 2006. (Current as of September 2007.) please see Appendix C for specific state citations. 


place can affect the pattern of cash flow and earn¬ 
ings. Large episodic jumps in earnings (produced, for 
example, by a decision to allow recovery of accrued 
under-recovery of fixed costs in a lump sum), can 
cloud financial analysts' ability to discern the true 
financial performance of a company. 

• Administrative Simplicity and Managing Regulatory 
Costs. Simplicity requires that any/all mechanisms 
be transparent with respect to both calculation of 


recoverable amounts and overall impact on utility 
earnings. Every mechanism will impose some incre¬ 
mental cost on all parties, since some regulatory re¬ 
sponsibilities are inevitable. The objective, therefore, 
is to structure mechanisms that lend themselves to a 
consistent and more formulaic process. This objective 
can be satisfied by providing clear rules prescribing 
what is considered acceptable/necessary as part of an 
investment plan. 


ES-6 


Aligning Utility Incentives with Investment in Energy Efficiency 












































Finding the right policy balance hinges on a wide range of 
factors that can influence how a cost recovery and perfor¬ 
mance incentive measure will actually work. These factors 
will include: industry structure (gas or electric utility, public 
or investor-owned, restructured or bundled); regulatory 
structure and process (types of test year, current rate de¬ 
sign policies); and utility operating environment (demand 
growth and volatility, utility cost and financial structure, 
structure of the energy efficiency portfolio). Given the 
complexity of many of these issues, most states defer to 
state utility regulators to fashion specific cost recovery and 
performance incentive mechanism(s). 

Emerging Models. 

Although the details of the policies and mechanisms 
for addressing the financial impacts of energy efficiency 
programs continue to evolve in jurisdictions across the 
country, the basic classes of mechanisms have been 
understood, applied, and debated for more than two 
decades. Most jurisdictions currently considering policies 
to remove financial disincentives to utility investment 
in energy efficiency are considering one or more of the 
mechanisms described above. Still, the persistent debate 
over recovery of lost margins and performance incen¬ 
tives in particular creates an interest in new approaches. 

In April 2007, Duke Energy proposed what is arguably 
the most sweeping alternative to traditional cost recovery, 
margin recovery and performance incentive approaches 
since the 1980s. Offered in conjunction with an energy 
efficiency portfolio in North Carolina, Duke's Energy Effi¬ 
ciency Rider encapsulates program cost recovery, recovery 
of lost margins, and shareholder incentives into one con¬ 
ceptually simple mechanism tied to the utility's avoided 
cost. The approach is based on the notion that, if energy 
efficiency is to be viewed from the utility's perspective 
as equivalent to a supply resource, the utility should be 
compensated for its investment in energy efficiency by an 
amount roughly equal to what it would otherwise spend 
to build the new capacity that is to be avoided. The Duke 
proposal would authorize the company, "to recover the 
amortization of and a return on 90 percent of the costs 
* avoided by producing save-a-watts." 


The proposal clearly represents an innovation in thinking 
regarding elimination of financial disincentives for utilities, 
and has intuitive appeal for its conceptual simplicity. The 
Duke proposal does represent a distinct departure from 
cost recovery and shareholder incentives convention. 

What is a simple and compelling concept is embedded 
in a formal mechanism that is quite complex, and the 
mechanism will likely engender substantial debate. 

A second emerging model is represented by the ISO New 
England's capacity auction process. This process allows 
demand-side resources to be bid into an auction along¬ 
side supply-side resources, and utilities and third-party 
energy efficiency providers are allowed to participate in 
the auction with energy efficiency programs. Winning 
bids receive a revenue stream that could, under certain 
circumstances, be used to offset direct program costs or 
lost margins, or could provide a source of performance 
incentives. The treatment of revenues received from the 
auction by a utility, however, is subject to allocation by its 
state utility commission(s), and the traditional approach 
to the treatment of off-system revenues is to credit them 
against jurisdictional revenue requirements. Therefore, the 
capability of this model to address the impacts described 
above depends largely on state regulatory policy. Whether 
this model ultimately is transferable to other areas of the 
country depends greatly on how power markets are struc¬ 
tured in these areas. 

Final Thoughts 

The history of utility energy efficiency investment is 
rich with examples of how state legislatures, regulatory 
commissions, and the governing bodies of publicly and 
cooperatively owned utilities have explored their cost 
recovery policy options. As these options are reconsidered 
and reconfigured in light of the trend toward higher util¬ 
ity investment in energy efficiency, this experience yields 
several lessons with respect to process. 

• Set cost recovery and incentive policy based on the 
direction of the market's evolution. The rapid develop¬ 
ment of technology, the likely integration of energy 
efficiency and demand response, continuing evolution 
of utility industry structure, the likelihood of broader 


National Action Plan for Energy Efficiency 


ES-7 


action on climate change, and a wide range of other 
uncertainties argue for cost recovery and incentive 
policies that can work with intended effect under a 
variety of possible futures. 

• Apply cost recovery mechanisms and utility perfor¬ 
mance incentives in a broad policy context. The poli¬ 
cies that affect utility investment in energy efficiency 
are many and varied and each will control, to some 
extent, the nature of financial incentives and disin¬ 
centives that a utility faces. Policies that could impact 
the design of cost recovery and incentive mechanisms 

i , 

include those having to do with carbon emissions 
reduction; non-C02 environmental control, such as 
NOX cap-and-trade initiatives; rate design; resource 
portfolio standards; and the development of more liq¬ 
uid wholesale markets for load reduction programs. 

• Test prospective policies. Complex mechanisms that 
have many moving parts cannot easily be under¬ 
stood unless the performance of the mechanisms is 
simulated under a wide range of conditions. This is 
particularly true of mechanisms that rely on projec¬ 
tions of avoided costs, prices, or program impacts. 
Simulation of impacts using financial modeling and/ 
or use of targeted pilots can be effective tools to test 
prospective policies. 

• Policy rules must be clear. There is a clear link be¬ 
tween the risk a utility perceives in recovering its 
costs, and disincentives to invest in energy efficiency. 
This risk is mitigated in part by having cost recovery 
and incentive mechanisms in place, but the efficacy 
of these mechanisms depends very much on the rules 
governing their application. While state regulatory 
commissions often fashion the details of cost recov¬ 
ery, lost margin recovery, and performance incentive 
mechanisms, the scope of their actions is governed 
by legislation. In some states, significant expenditures 
on energy efficiency by utilities are precluded by lack 
of clarity regarding regulators' authority to address 
one or more of the financial impacts of these expen¬ 
ditures. Legislation specifically authorizing or requir¬ 
ing various mechanisms creates clarity for parties and 
minimizes risk. 


• Collaboration has value. The most successful and 
sustainable cost recovery and incentive policies are 
those that are based on a consultative process that, 
in general, includes broad agreement on the aims of 
the energy efficiency investment policy. 

• Flexibility is essential. Most of the states that have 
had significant efficiency investment and cost recov¬ 
ery policies in place for more than a few years have 
found compelling reasons to modify these policies 
at some point. These changes reflect an institutional 
capacity to acknowledge weaknesses in existing ap¬ 
proaches and broader contextual changes that render 
prior approaches ineffective. Policy stability is desir¬ 
able, and policy changes that have significant impacts 
on earnings or prices can be particularly challeng¬ 
ing. However, it is the stability of impact rather than 
adherence to a particular model that is important in 
addressing financial disincentives to invest. 

• Culture matters. One important test of a cost recovery 
and incentives policy is its impact on corporate cul¬ 
ture. A policy providing cost recovery is an essential 
first step in removing financial disincentives associ¬ 
ated with energy efficiency investment, but it will not 
change a utility's core business model. Earnings are 
still created by investing in supply-side assets and sell¬ 
ing more energy. Cost recovery plus a policy enabling 
recovery of lost margins might make a utility indiffer¬ 
ent to selling or saving a kilowatt-hour or therm, but 
still will not make the business case for aggressive 
pursuit of energy efficiency. A full complement of 
cost recovery, lost margin recovery, and performance 
incentive mechanisms can change this model, and 
likely will be needed to secure sustainable funding for 
energy efficiency at levels necessary to fundamentally 
change resource mix. 

Notes _ 

1. Revenue requirement refers to the sum of the costs that a utility 
is authorized to recover through rates. 

2. For example, see the National Association of State Utility 
Consumer Advocates' Resolution on Energy Conservation and 
Decoupling, June 12, 2007. 


ES-8 


Aligning Utility Incentives with Investment in Energy Efficiency 



Introduction 




Improving the energy efficiency of homes, businesses, 
schools, governments, and industries—which collec¬ 
tively consume more than 70 percent of the natural gas 
and electricity used in the United States—is one of the 
most constructive, cost-effective ways to address the 
challenges of high energy prices, energy security and 
independence, air pollution, and global climate change. 
Mining this efficiency could help us meet on the order 
of 50 percent or more of the expected growth in U.S. 
consumption of electricity and natural gas in the coming 
decades, yielding many billions of dollars in saved energy 
bills and avoiding significant emissions of greenhouse 
gases and other air pollutants half to all of the expected 
load growth for electricity and natural gas over the next 
10 to 15 years, yielding many billions of dollars in saved 
energy bills and avoiding significant emissions of green¬ 
house gases and other air pollutants. 1 

Recognizing this large untapped opportunity, more than 
60 leading organizations representing diverse stakehold¬ 


ers from across the country joined together to develop the 
National Action Plan for Energy Efficiency. 2 The Action Plan 
identifies many of the key barriers contributing to under¬ 
investment in energy efficiency; outlines five key policy 
recommendations for achieving all cost-effective energy 
efficiency, focusing largely on state-level energy efficiency 
policies and programs; and provides a number of options 
to consider in pursuing these recommendations (Figure 
1-1). As of November 2007, nearly 120 organizations have 
endorsed the Action Plan recommendations and made 
public commitments to implement them in their areas. 
Aligning utility incentives with the delivery of cost-effective 
energy efficiency is key to making the Action Plan a reality. 

1.1 Energy Efficiency Investment 

Actual and prospective investment in energy efficiency 
programs is on a steep climb, driven by a variety of 
resource, environmental, and customer cost mitigation 


Figure 1-1. Annual Utility Spending on Electric Energy Efficiency 






& 


(o 




■c 




£ 5 " 


& 


© 














'v 


© 






'v 




© 


Sources: El A, 2006 (for 2005 data); Consortium for Energy Efficiency, 2006. 
National Action Plan for Energy Efficiency 


Year 


1-1 



















Figure 1-2. National Action Plan for Energy Efficiency Recommendations and Options 


Recognize energy efficiency as a high-priority 
energy resource. 

Options to consider: 

• Establishing policies to establish' energy efficiency as a 
priority resource. 

• Integrating energy efficiency into utility, state, and 
regional resource planning activities. 

• Quantifying and establishing the value of energy effi¬ 
ciency, considering energy savings, capacity savings, and 
environmental benefits, :as appropriate. 

Make a strong, long-term commitment to imple¬ 
ment cost-effective energy efficiency as a 
resource. 

Options to consider: 

• Establishing appropriate cost-effectiveness tests for a 
portfolio of programs to reflect the long-term benefits 
of energy efficiency. 

• Establishing the potential for long-term, cost-effective 
energy efficiency savings by customer class through 
proven programs, innovative initiatives, and cutting- 
edge technologies. 

• Establishing funding requirements for delivering long¬ 
term, cost-effective energy efficiency. 

• Developing long-term energy saving goals as part of 
energy planning processes. 

• Developing robust measurement and verification 
procedures. 

• Designating which organization(s) is responsible for 
administering the energy efficiency programs. 

• Providing for frequent updates to energy resource plans 
to accommodate new information and technology. 

Broadly communicate the benefits of and 
opportunities for energy efficiency. 

Options to consider: 

• Establishing and educating stakeholders o,n the business 
case for energy efficiency at the state, utility, and other 
appropriate level, addressing relevant customer, utility, 
and societal perspectives. 


• Communicating the role of energy efficiency in lower¬ 
ing customer energy bills and system costs and risks 
over time. 

• Communicating the role of building codes, appli¬ 
ance standards, and tax and other incentives. 

Provide sufficient, timely, and stable 
program funding to deliver energy 
efficiency where cost-effective. 

Options to consider: 

• Deciding on and committing to a consistent way for 
program administrators to recover energy efficiency 
costs in a timely manner. 

• Establishing funding mechanisms for energy ef¬ 
ficiency from among the available options, such as 
revenue requirement or resource procurement fund¬ 
ing, system benefits charges, rate-basing, shared- 
savings, and incentive mechanisms. 

• Establishing funding for multi-year period. 

Modify policies to align utility incentives 
with the delivery of cost-effective energy 
efficiency and modify ratemaking practices 
to promote energy efficiency investments. 

Options to consider: 

• Addressing the typical utility throughput incentive 
and removing other regulatory and management 
disincentives to energy efficiency. 

• Providing utility incentives for the successful man¬ 
agement of energy efficiency programs. 

• Including the impact on adoption of energy ef¬ 
ficiency as one of the goals of retail rate design, 
recognizing that it must be balanced with other 
objectives. 

• Eliminating rate designs that discourage energy 
efficiency by not increasing costs as customers con¬ 
sume more electricity or natural gas. 

• Adopting rate designs that encourage energy ef¬ 
ficiency by considering the unique characteristics of 
each customer class and including partnering tariffs 
with other mechanisms that encourage energy effi¬ 
ciency, such as benefit-sharing programs and on-bill 
financing. 


Source: National Action Plan for Energy Efficiency, 2006a. 


1-2 


Aligning Utility Incentives with Investment in Energy Efficiency 



concerns. Nevada Power is proposing substantial in¬ 
creases in energy efficiency funding as a strategy for 
compliance with the state's aggressive resource portfolio 
standard. Funding in California has roughly doubled since 
2004 as utilities supplement public charge monies with 
"procurement funds." 3 Michigan and Illinois have been 
debating significant efficiency funding requirements, and 
the Texas legislature has doubled the percentage of load 
growth that must be offset by energy efficiency, imply¬ 
ing a significant increase in efficiency program funding. 
Integrated resource planning cases and various regulatory 
settlements from Delaware to North Carolina and Mis¬ 
souri are producing new investment in energy efficiency. 
Data recently compiled by the Consortium for Energy 
Efficiency (2006) show total estimated energy efficiency 
spending by electric utilities exceeding $2.3 billion in 
2006, on par with peak energy efficiency spending in the 
mid-1990s. With the rise in funding, there is broad inter¬ 
est across the country in refashioning regulatory policies 
to eliminate financial disincentives and barriers to utility 
investment in energy efficiency. 

1.1.1 Understanding Financial Disincentives to 
Utility Investment 

Not unexpectedly, the rise in interest in energy efficiency 
investment has produced a resurgent interest in how 
the costs associated with energy efficiency programs 


are recovered, and whether, in the light of what many 
believe to be compelling reasons for greater program 
spending, utilities have sufficient incentive to aggres¬ 
sively pursue these investments. 

Energy efficiency programs can have several financial 
impacts on utilities that create disincentives for utilities 
to promote energy efficiency more aggressively. Policy¬ 
makers have developed several mechanisms intended to 
minimize or eliminate these impacts. 

Utility concerns for these three impacts have had a pro¬ 
found effect on energy efficiency investment policy at 
the corporate and state level for over 20 years, and the 
concerns continue to create tension as utilities are called 
upon to boost energy efficiency spending. 

Although the nature of today's cost recovery and incen¬ 
tives discussion may be reminiscent of a similar discus¬ 
sion almost two decades ago, the context in which this 
discussion is taking place is very different. Not only have 
parties gained valuable experience related to the use of 
various cost recovery and incentive mechanisms, but the 
policy landscape has also been reshaped fundamentally. 

Industry Structure 

The past two decades have witnessed significant 
industry reorganization in both wholesale and retail 


Table 1-1. Utility Financial Concerns 

Potential Impact 

Potential Solutions 

Energy efficiency expenditures adversely impact 
utility cash flow and earnings if not recovered in a 
timely manner. 

• Recovery through general rate case 

• Energy efficiency cost recovery surcharges 

• System benefits charge 

Energy efficiency will reduce electricity or gas sales 
and revenues and potentially lead to under-recovery 
of fixed costs. 

/ 

• Lost revenue adjustment mechanisms that allow recovery 
of revenue to cover fixed costs 

• Decoupling mechanisms that sever the link between 
sales and margin or fixed-cost revenues 

• Straight fixed-variable (SFV) rate design (allocate fixed 
costs to fixed charges) 

Supply-side investments generate substantial returns 
for investor-owned utilities. Typically, energy efficiency 
investments do not earn a return and are, therefore, less 
financially attractive . 4 

• Capitalize efficiency program costs and include in rate base 

• Performance incentives that reward utilities for superior 
performance in delivering energy efficiency 


National Action Plan for Energy Efficiency 


1-3 











power and natural gas markets. Investor-owned electric 
utilities, particularly in the Northeast and sections of 
the Midwest, unbundled (i.e., separated the formerly 
integrated functions of generation, transmission, and 
distribution) in anticipation of retail competition. Inves¬ 
tor-owned natural gas utilities also have gone through 
a similar unbundling process, albeit one that has been 
quite different in its form. 5 Unbundling creates two 
effects relevant to the issues of energy efficiency cost 
recovery and incentives. 

First, unbundling of industry structure also unbundles 
the value of demand-side programs, in the sense that 
none of the entities created by unbundling an inte¬ 
grated company can capture the full value of an energy 
efficiency investment. An integrated utility can capture 
the value of an energy efficiency program associated 
with avoided generation, transmission, and distribution 
costs. The distribution company produced by unbun¬ 
dling an integrated utility can only directly capture the 
value associated with avoided distribution. One of the 
principal arguments for public benefits funds was that 
they could effectively re-bundle this value. 6 

Second, unbundling changes the financial implications 
of energy efficiency investment as a function of chang¬ 
ing cost-of-service structures. The corporate entity sub¬ 
ject to continued traditional cost-of-service regulation 
following unbundling typically is the distribution or 
wires company. The actual electricity or natural gas sold 
to consumers is often purchased by consumers directly 
from competitive or, more commonly, default service 
providers. In some states, this is also the distribution 
company. The distribution company adds a distribution 
service charge to this commodity cost, often levied per 
unit of throughput, which represents its cost to move 
the power or gas over its system to the customer. Often, 
this charge as levied by electric utilities reflects a higher 
percentage of fixed costs than had been the case when 
the utility provided bundled service, simply because the 
utility no longer incurs the variable costs associated with 
power production. 7 In the case of the distribution com¬ 
pany, the potential impact on utility earnings of a drop 
in sales volume is more pronounced. 8 


Renewed Focus on Resource Planning 

Industry restructuring was accompanied by a steep decline 
in the popularity and practice of resource planning, which 
had supported much of the early rise in energy efficiency 
programming. The last several years have seen a resur¬ 
gence of interest in resource planning (in both bundled 
and restructured markets) and renewal of interest in 
ratepayer-funded energy efficiency as a resource option 
capable of mitigating some of this market volatility. 9 

The intervening years have reshaped the practice of 
resource planning into a more sophisticated and, some¬ 
times, multi-state process, focused much more on an 
acknowledgement of and accommodation to the costs 
and risks surrounding the acquisition of new resources. 
Energy efficiency investments increasingly are given 
proper value for their ability to mitigate a variety of 
policy and financial risks. 


Distinctions With a Difference: Gas v. 
Electric Utilities and Investor-Owned 
v. Publicly and Cooperatively Owned 
Utilities 


Throughout this Report, distinctions are made between 
gas and electric utilities and between those that are 
investor- and publicly or cooperatively owned. In some 
cases, these distinctions create very important differ¬ 
ences in how barriers might be perceived and in wheth¬ 
er particular cost recovery and incentive mechanisms 
are applicable and appropriate. For example, gas and 
electric utilities face very different market dynamics and 
can have different cost structures. Declining gas use per 
customer across the industry creates greater financial 
sensitivity to the revenue impacts of energy efficiency 
programs. Publicly and cooperatively owned utilities 
operate under different financial and, in most states, 
regulatory structures than investor-owned companies. 
And just the fact that publicly and cooperatively owned 
utilities are owned by their customers creates a different 
set of expectations and obligations. At the same time, 
all utilities are sensitive to many of the same financial 
implications, particularly regarding recovery of direct 
program costs and lost margins. Wherever possible, 
the Report highlights specific instances in which these 
distinctions are particularly important. 


1-4 


Aligning Utility Incentives with Investment in Energy Efficiency 



Rising Commodity Costs and Flattening Sales 

The run-up in natural gas prices over the past several 
years has made the case for gas utility implementa¬ 
tion of energy efficiency programs more compelling as 
a strategy for helping manage customer energy costs. 
However, where once these programs were implement¬ 
ed in at least a modestly growing gas market, efficiency 
programs are now combined with flat or declining use 
per customer, making recovery of program costs and 
lost margins a more urgent matter. 

Acknowledgement of Climate Risk 

There is a growing recognition among state policy¬ 
makers and electric utilities that action is required to 
mitigate the impacts of climate change and/or hedge 
against the likelihood of costly climate policies. Energy 
efficiency investments are valued for their ability to 
reduce carbon emissions at low cost by reducing the 
use of existing high-carbon emitting sources and the 
deferral of the need for new fossil capacity. Some of the 
largest electric utilities in the country are forming their 
business strategies around the likelihood of action on 
climate policy, and making energy efficiency pivotal in 
these strategies. Although the environmental attributes 
of energy efficiency have long been emphasized in 
arguing the business case for energy efficiency invest¬ 
ment, particularly in the electric industry, today that 
argument appears largely to be over, and attention is 
shifting to the practical elements of policies that can 
support scaled-up investment in efficiency. 10 

As utilities increasingly turn to energy efficiency as a key 
resource, they will look more closely at the links between 
efficiency, sales, and financial margins, sharpening the 
question of whether ratemaking policies that reward 
increases in sales are sustainable. Perhaps less obvious, as 
policies are implemented to reduce carbon emissions, they 
likely will create new pathways for capturing the financial 
value of efficiency that, in turn, will require policy-makers 
to consider whether current approaches to cost recovery 
and incentives are aligned with these broader policies. 

Advancing Technology 

The technology and therefore, the practice of en¬ 
ergy efficiency, appear on the edge of significant 


transformation, particularly in the electric utility industry. 
The formerly bright line between energy efficiency and 
demand response 11 is blurring with the growing adop¬ 
tion of advanced metering technologies, innovative 
pricing regimes, and smart appliances. 12 Emerging tech¬ 
nologies enable utilities to more precisely target valu¬ 
able load reductions, and offer consumers prices that 
more closely represent the time-varying costs to provide 
energy. Ultimately, when consumers can receive and act 
on time- and location-specific energy prices, this will 
affect the types of energy efficiency measures possible 
and needed, and efficiency program design and funding 
will change accordingly. With respect to the immediate 
issues of cost recovery and incentives, the incorporation 
of increasing amounts of demand response in utility 
resource portfolios can change the financial implica¬ 
tions of these portfolios, as programs targeted at peak 
demand reduction as opposed to energy consumption 
reduction can have a substantially different impact on 
the recovery of fixed costs. 13 

1.1.2 Current Status 

The answer to "what has changed?" then, is that the 
rationale for investment in efficiency has been re¬ 
thought, refocused, and strengthened, with ratepayer 
funding rising to levels eclipsing those of the late 1980s/ 
early 1990s. And as funding rises, the need to address 
and resolve the issues surrounding energy efficiency 
program cost recovery and performance incentives take 
on greater importance and urgency. At the same time, 
many of the utilities being asked to make this invest¬ 
ment are structured differently today than two decades 
ago during the last efficiency investment boom, so 
today's efficiency initiatives will have different financial 
impacts on the utility. Table 1-2 presents a best estimate 
of the current status of energy efficiency cost recovery 
and utility performance incentive activity across the 
country. Where a cell reads "Yes" without reference 
to gas or electric, the policy applies to both gas and 
electric utilities. 

Table 1-2 reveals that many states have implemented 
policies that support cost recovery and/or performance 
incentives to some extent. Even those states that are not 
shown as having a specific program cost recovery policy 


National Action Plan for Energy Efficiency 


1-5 


Table 1-2. The Status of Energy Efficiency Cost Recovery and Incentive 
Mechanisms for Investor-Owned Utilities 


State 

Direct Cost Recovery 

Fixed Cost Recovery 

Performance 

Incentives 

Rate Case 

System 

Benefits 

Charge 

Tariff Rider/ 
Surcharge 

Decoupling 

Lost Revenue 
Adjustment 
Mechanism 

Alabama 

Yes 






Alaska 







Arizona 

Yes (electric) 

Yes (electric) 


Pending (gas) 


Yes (electric) 

Arkansas 




Yes (gas) 



California 

Yes 

Yes 


Yes 


Yes 

Colorado 

Yes 


Yes 

Pending 


Yes 

Connecticut 


Yes (electric) 



Yes 

Yes 

Delaware 

Yes 



Pending 



District of 

Columbia 

Yes 



Pending 

(electric) 



Florida 



Yes (electric) 




Georgia 

Yes 





Yes (electric) 

Hawaii 




Pending 

(electric) 


Yes 

Idaho 

Yes (electric) 



Yes (electric) 



Illinois 

Yes (electric) 






Indiana 

Yes 



Yes (gas) 

Yes 

Yes 

Iowa 

Yes 


Yes 




Kansas 






Yes 

Kentucky 



Yes 

Pending (gas) 

Yes 

Yes 

Louisiana 


t 





Maine 


Yes (electric) 





Maryland 




Yes (gas) 
Pending 
(electric) 



Massachusetts 


Yes (electric) 


Pending 

(electric) 

Yes 

Yes (electric) 

Michigan 




Pending (gas) 



Minnesota 

Yes 



Yes 


Yes 

Mississippi 

Yes 







Source: Kushler et al., 2006. (Current as of September 2007.) Please see Appendix C for specific state citations. 


1-6 


Aligning Utility Incentives with Investment in Energy Efficiency 














































Table 1-2. The Status of Energy Efficiency Cost Recovery and Incentive 
Mechanisms for Investor-Owned Utilities (continued) 

State 

Direct Cost Recovery 

Fixed Cost Recovery 

Performance 

Incentives 

Rate Case 

System 

Benefits 

Charge 

Tariff Rider/ 
Surcharge 

Decoupling 

Lost Revenue 
Adjustment 
Mechanism 

Missouri 




Yes (gas) 



Montana 

Yes (gas) 

Yes (electric) 




Yes 

Nebraska 







Nevada 

Yes (electric) 



Yes (gas) 


Yes (electric) 

New Hampshire 


Yes (electric) 


Pending 

(electric) 


Yes (electric) 

New Jersey 

i 

Yes 


Yes (gas) 

Pending 

(electric) 



New Mexico 

Yes 



Pending (gas) 



New York 


Yes (electric) 


Yes 



North Carolina 




Yes (gas) 



North Dakota 







Ohio 



Yes (electric) 

Yes (gas) 

Yes (electric) 

Yes (electric) 

Oklahoma 







Oregon 


Yes 


Yes (gas) 



Pennsylvania 

Yes 






Rhode Island 


Yes (electric) 


Yes 


Yes 

South Carolina 






Yes 

South Dakota 







Tennessee 







Texas 

Yes 






Utah 

Yes (electric) 


Yes (electric) 

Yes (gas) 

■ 


Vermont 


Yes (electric) 



Yes 

Yes 

Virginia 




Pending (gas) 



Washington 

Yes (electric) 


Yes (electric) 

Yes (gas) 



West Virginia 







Wisconsin 

Yes (electric) 

Yes (electric) 


Pending 

(electric) 



Wyoming 








1 Source: Kushler et al„ 2006. (Current as of September 2007.) Please see Appendix C for specific state citations. 


National Action Plan for Energy Efficiency 


1-7 















































T 


do allow recovery of approved program costs through 
rate cases. The table also shows that there is a substantial 
amount of activity surrounding gas revenue decoupling. 
However, despite the significant level of activity around 
the country, relatively few states have implemented com¬ 
prehensive policies that address program cost recovery, 
recovery of lost margins, and performance incentives. The 
challenge to policy-makers is whether the level of invest¬ 
ment envisioned can be achieved without broader action 
to implement such comprehensive policies. 

1.2 Aligning Utility Incentives 
with Investment in Energy 
Efficiency Report _ 

This report on Aligning Utility Incentives with Investment 
in Energy Efficiency describes the financial effects on 
a utility of its spending on energy efficiency programs; 
how those effects could constitute barriers to more 
aggressive and sustained utility investment in energy 
efficiency; and how adoption of various policy mecha¬ 
nisms can reduce or eliminate these barriers. This Report 
also provides a number of examples of such mechanisms 
drawn from the experience of a number of utilities and 
states. 

The Report was prepared in response to a need identi¬ 
fied by the Action Plan Leadership Group (see Appendix 
A for a list of group members) for additional practical 
information on mechanisms for reducing these barriers 
to support the Action Plan recommendations to "provide 
sufficient, timely, and stable program funding to deliver 
energy efficiency where cost-effective" and "modify 
policies to align utility incentives with the delivery of 
cost-effective energy efficiency and modify ratemaking 
practices to promote energy efficiency investments." Key 
options to consider under this recommendation include 
committing to a consistent way to recover costs in a 
timely manner, addressing the typical utility throughput 
incentive, and providing utility incentives for the success¬ 
ful management of energy efficiency programs. 


There are a number of possible regulatory mechanisms 
for addressing both options, as well as for ensuring 
recovery of prudently incurred energy efficiency program 
costs. Determining which mechanism will work best for 
any given jurisdiction is a process that takes into account 
the type and financial structure of the utilities in that 
jurisdiction, existing statutory and regulatory authority, 
and the size of the energy efficiency investment. The net 
impact of an energy efficiency cost recovery and perfor¬ 
mance incentives policy will be affected by a wide variety 
of other factors, including rate design and resource pro¬ 
curement strategies, as well as broader considerations 
such as the rate of demand growth and environmental 
and resource policies. 

Specifically, the Report provides a description of three 
financial effects that energy efficiency spending can have 
on a utility: 

• Failure to recover program costs in a timely way has a 
direct impact on utility earnings. 

• Reductions in sales due to energy efficiency can re¬ 
duce utility financial margins. 

• As a substitute for new supply-side resources, energy 
efficiency reduces the earnings that a utility would 
otherwise earn on the supply resource. 

This Report examines how these effects create disincen¬ 
tives to utility investment in energy efficiency and the 
policy mechanisms that have been developed to address 
these disincentives. In addition, this Report examines the 
often complex policy environment in which these effects 
are addressed, emphasizing the need for clear policy ob¬ 
jectives and for an approach that explicitly links together 
the impacts of policies to address utility financial disin¬ 
centives. Two emerging models for addressing financial 
disincentives are described, and the Report concludes 
with a discussion of key lessons for states interested in 
developing policies to align financial incentives with util¬ 
ity energy efficiency investment. 

The subject of financial disincentives and possible remedies 
has been debated for over two decades, and there remain 
several unresolved and contentious issues. This Report does 


1-8 


Aligning Utility Incentives with Investment in Energy Efficiency 


not attempt to resolve these issues. Rather, by providing 
discussion of the financial effects of utility efficiency invest¬ 
ment, and of the possible policy options for addressing 
these effects, this Report is intended to deepen the under¬ 
standing of these issues. In addition, this Report is intend¬ 
ed to provide specific examples of regulatory mechanisms 
for addressing financial effects for those readers exploring 
options for reducing financial disincentives to sustained 
utility investment in energy efficiency. 

This Report was prepared using an extensive review of 
the existing literature on energy efficiency program cost 
recovery, lost margin recovery, and utility performance 
incentives—a literature that reaches back over 20 years. 
In addition, this Report uses a broad review of state 
statutes and administrative rules related to utility energy 
efficiency program cost recovery. Key documents for the 
reader interested in additional information include: 

• Aligning Utility Interests with Energy Efficiency Objec¬ 
tives: A Review of Recent Efforts at Decoupling and 
Performance Incentives, Martin Kushler, Dan York, 
and Patti Witte, American Council for an Energy Effi¬ 
cient Economy, Report Number U061, October 2006. 

i 

• Decoupling for Electric and Gas Utilities: Frequently 
Asked Questions (FAQ), September 2007, available at 
<http://www.naruc.org>. 

• A variety of documents and presentations developed 
by RAP, available online at <http://www.raponline. 
org>. 

• Ken Costello, Revenue Decoupling for Natural Gas 
Utilities—Briefing Paper, National Regulatory Re¬ 
search Institute, April 2006. 

• American Gas Association, Natural Gas Rate Round- 
Up, Update on Decoupling Mechanisms—April 2007. 

• DOE, State and Regional Policies That Promote En¬ 
ergy Efficiency Programs Carried Out by Electric and 
Gas Utilities: A Report to the United States Congress 
Pursuant to Section 139 of the Energy Policy Act of 
2005, March 2007. 

• Revenue Decoupling: A Policy Brief of the Electricity 
Consumers Resource Council, January 2007. 


1.2.1 How to Use This Report 

This Report focuses on the issues associated with 
financial implications of utility-administered programs. 
For the most part, these issues are the same whether 
the funding flows from a system benefits charge or 
is authorized by regulatory action, with the exception 
that a system benefits charge effectively resolves issues 
associated with program cost recovery. In addition, 
the issues related to the effect of energy efficiency on 
utility financial margins apply whether the efficiency is 
produced by a utility-administered program or through 
building codes, appliance standards, or other initiatives 
aimed at reducing energy use. This Report is intended 
to help the reader answer the following questions: 

• How are utilities affected financially by their invest¬ 
ments in energy efficiency? 

• What types of policy mechanisms can be used to ad¬ 
dress the various financial effects of energy efficiency 
investment? 

• What are the pros and cons of these mechanisms? 

• What states have employed which types of mecha¬ 
nisms and how have they been structured? 

• What are the key differences related to financial 
impacts between publicly and investor-owned utilities 
and between electric and gas utilities? 

• What new models for addressing these financial ef¬ 
fects are emerging? 

• What are the important steps to take in attempting 
to address financial barriers to utility investment in 
energy efficiency? 

This Report is intended for utilities, regulators and 
regulatory staff, consumer representatives, and energy 
efficiency advocates with an interest in addressing these 
financial barriers. 

1.2.2 Structure of the Report 

Chapter 2 of the Report outlines the basic financial 
effects associated with utility energy efficiency invest¬ 
ment, reviews the key related policy issues, and provides 


National Action Plan for Energy Efficiency 


1-9 


I 


a case study of how a comprehensive approach to ad¬ 
dressing financial disincentives to utility energy efficien¬ 
cy investment can have an impact on utility corporate 
culture. Chapter 3 outlines a range of possible objec¬ 
tives that policy-makers should consider in designing 
policies to address financial incentives. 

Chapters 4, 5, and 6 provide examples of specific 
program cost recovery, lost margin recovery, and utility 
performance incentive mechanisms, as well as a review 
of possible pros and cons. Chapter 7 provides an over¬ 
view of two emerging cost recovery and performance 
incentive models, and the Report concludes with a 
discussion of important lessons for developing a policy 
to eliminate financial disincentives to utility investment 
in energy efficiency. 

1.2.3 Development of the Report 

The Report on Aligning Utility Incentives with Invest¬ 
ment in Energy Efficiency is a product of the Year Two 
Work Plan for the National Action Plan for Energy 
Efficiency. In addition to direction and comment by the 
Action Plan Leadership Group, this Guide was prepared 
with highly valuable input of an Advisory Group. Val 
Jensen of ICF International served as project manager 
and primary author of the Report with assistance from 
Basak Uluca, under contract to the U.S. Environmental 
Protection Agency. 

The Advisory Group members are: 

• Lynn Anderson, Idaho Public Service Commission 

\ 

• Jeff Burks, PNM Resources 

• Sheryl Carter, Natural Resources Defense Council 

• Dan Cleverdon, DC Public Service Commission 

• Roger Duncan, Austin Energy 

• Jim Gallagher, New York State Public Service 
Commission 

• Marty Haught, United Cooperative Service 

• Leonard Haynes, Southern Company 


• Mary Healey, Connecticut Office of Consumer 
Counsel 

• Denise Jordan, Tampa Electric Company 

• Don Low, Kansas Corporation Commission 

• Mark McGahey, Tristate Generation and Transmission 
Association, Inc. 

• Barrie McKay, Questar Gas Company 

• Roland Risser, Pacific Gas & Electric 

• Gene Rodrigues, Southern California Edison 

• Michael Shore, Environmental Defense 

• Raiford Smith, Duke Energy 

• Henry Yoshimura, ISO New England Inc. 

1.3 Notes 

1. See the National Action Plan for Energy Efficiency (2006), avail¬ 
able at <www.epa.gov/cleanenergy/actionplan/report.htm>. 

2. See <www.epa.gov/actionplan>. 

3. "Procurement funds" are monies that are approved by the 
California Public Utilities Commission for procurement of new 
resources as part of what is essentially an integrated resource 
planning process in California. 

4. Publicly and cooperatively owned utilities operate under differ¬ 
ent financial structures than investor-owned utilities and do not 
face the same issue of earnings comparability, as they do not pay 
returns to eguity holders. 

5. Unbundling in the gas industry took a much different form than it 
did in the electric industry. Gas utilities were never integrated, in 
the sense that they were responsible for production, transmission, 
and distribution. Gas utilities always have principally served the 
distribution function. However, prior to the early 1980s, most gas 
utilities were responsible for contracting for gas to meet residen¬ 
tial, commercial, and industrial demand. Gas industry restructur¬ 
ing led to larger customers being given the ability to purchase 
gas and transportation service directly, as well as to an end to the 
typical long-term bundled supply/transportation contracting that 
gas utilities formerly had engaged in. 

6. Some wholesale markets are developing mechanisms to account 
for the value of demand-side programs. For example, ISO-New 
England's Forward Capacity Auction allows providers of demand 
resources to bid demand reductions into the auction. 


1-10 


Aligning Utility Incentives with Investment in Energy Efficiency 



7. Although natural gas utilities have never had the capital-intensive 
financial structure common to integrated electric utilities, they 
historically have tended to be more vulnerable financially to de¬ 
clines in sales because a much greater fraction of the cost of gas 
service has been associated with the cost of the gas commodity. 
Prior to gas industry restructuring this problem was even more 
acute for those utilities procuring gas under contracts with take- 
or-pay or fixed-charge clauses. 

8. According to the Regulatory Assistance Project, the loss of sales 
due to successful implementation of energy efficiency will lower 
utility profitability, and the effect may be quite powerful under 
traditional rate design. "For example, a 5% decrease in sales 
can lead to a 25% decrease in net profit for an integrated util¬ 
ity. For a stand-alone distribution utility, the loss to net profit is 
even greater—about double the impact." See Harrington, C., C. 
Murray, and L. Baldwin (2007). Energy Efficiency Policy Toolkit. 
Regulatory Assistance Project, p. 21. <www.raponline.org> 

9. A number of studies have examined the ability of energy ef¬ 
ficiency and particularly, demand response programs, to reduce 
power prices by cutting demand during high-price periods. 
Because the marginal costs of power typically exceed average 
costs during these periods, efficiency programs targeted at high 
demand periods often will yield benefits for all ratepayers, even 
non-participants. See, for example, Direct Testimony of Bernard 


Neenan on Behalf of the Citizens Utility Board and the City Of 
Chicago, Cub-City Exhibit 3.0 October 30, 2006, ICC Docket No. 
06-0617, State Of Illinois, Illinois Commerce Commission. 

10. See, for example: "Greenhouse Gauntlet," 2007 CEO Forum, 
Public Utilities Fortnightly, June 2007. Pacific Gas and Electric 
(2007). Global Climate Change, Risks, Challenges, Opportunities 
and a Call to Action. <7www.pge.com/includes/docs/pdfs/about_ 
us/environment/features/global_climate_06.pdf> 

11. Energy efficiency traditionally has been defined as an overall 
reduction in energy use due to use of more efficiency equipment 
and practices, while load management, as a subset of demand 
response has been defined as reductions or shifts in demand with 
minor declines and sometimes increases in energy use. 

12. There remain important distinctions between dispatchable 
demand response and energy efficiency, including the ability to 
participate in wholesale markets. 

13. For example, a demand-response program that reduces coinci¬ 
dent peak demand but has little impact on sales could lead to a 
financial benefit for a utility, as its costs might decrease by more 
than its revenues if the cost of delivering power at the peak 
period exceeds the price for that power. 


i 


National Action Plan for Energy Efficiency 


1-11 














This chapter outlines the potential financial effects a utility may face when investing in energy efficiency 
and reviews key related policy issues. In addition, it provides a case study of how a comprehensive ap¬ 
proach to addressing financial disincentives to utility energy efficiency investment can have an impact on 
utility corporate culture and explores the issue of regulatory risk. 


2.1 Overview 

Investment in energy efficiency programs has three 
financial effects that map generally to specific types of 
costs incurred by utilities. 

• Failure to recover program costs in a timely way has a 
direct impact on utility earnings. 

• Reductions in sales due to energy efficiency can 
reduce utility financial margins. 

• As a substitute for new supply-side resources, energy 
efficiency reduces the earnings that a utility would 
otherwise earn on the supply resource. 

How these effects are addressed creates the incentives 
and disincentives for utilities to pursue investment in en¬ 
ergy efficiency. Ultimately, it is the combined effect on 
utility margins of policies to address these impacts that 
will determine how well utility financial interests align 
with investment in energy efficiency. 

These effects are artifacts of utility regulatory policy 
and the general practice of electricity and natural gas 
rate-setting. Individual state regulatory policy and 
practice will influence how these effects are addressed 
in any given jurisdiction. Even where broad consensus 
exists on the need to align utility and customer interests 
in the promotion of energy efficiency, the policy and 
institutional context surrounding each utility dictates the 
specific nature of incentives and disincentives "on the 
street." The purpose of this chapter is to briefly review 
some of the important policy considerations that will 


affect how the financial implications introduced above 
are treated. 

Two broad distinctions are important when considering 
policy context. The first is between investor-owned and 
publicly and cooperatively owned utilities. Every state 
regulates investor-owned utilities. 1 Most states do not 
regulate publicly or cooperatively owned utilities except 
in narrow circumstances. Instead, these entities typically 
are regulated by local governing boards in the case of 
municipal utilities, or are governed by boards repre¬ 
senting cooperative members. Public and cooperative 
utilities face many of the same financial implications of 
energy efficiency investment. They set prices in much 
the same way as investor-owned utilities, and have fixed 
cost coverage obligations just as investor-owned utilities 
do. Because these utilities are owned by their custom¬ 
ers, it is commonly accepted that customer and utility 
interests are more easily aligned. However, because mu¬ 
nicipal utilities often fund city services through transfers 
of net operating margins into other city funds, there 
can be pressure to maintain sales and revenues despite 
policies supportive of energy efficiency. 

The second distinction is between electric and natural 
gas utilities. This distinction is less between forms of 
regulation and more between the nature of the gas and 
electric utility businesses. Natural gas utilities historically 
have operated as distributors. Although many gas utili¬ 
ties continue to purchase gas on behalf of customers, 
the costs of these purchases are simply passed through 
to customers without mark-up. Many electric utilities, 
by contrast, build and operate generating facilities. 


National Action Plan for Energy Efficiency 


2-1 




Thus, the capital structures of the two types of utilities 
have differed significantly. 2 Electric utilities, while more 
capital intensive in the aggregate, historically have had 
higher variable costs of operation relative to the total 
cost of service than gas utilities. In other words, while 
electric utilities required more capital, fixed capital costs 
represented a larger fraction of the jurisdictional rev¬ 
enue requirement for gas utilities. This has made gas 
utilities more sensitive to unexpected sales fluctuations 
and fostered greater interest in various forms of lost 
margin recovery. 

Much of the discussion of mechanisms for aligning util¬ 
ity and customer interests related to energy efficiency 
investment assumes the utility is an investor-owned 
electric utility. However, some issues and their appropri¬ 
ate resolution will differ for publicly and cooperatively 
owned utilities and for natural gas utilities. These differ¬ 
ences will be highlighted where most significant. 

This chapter reviews each of the three financial effects 
of utility energy efficiency spending and then briefly ex¬ 
amines some of the policy issues that each raises. More 
detailed examples of policy mechanisms for addressing 
each effect are provided in following chapters. 

2.2 Program Cost Recovery 

The first effect is associated with energy efficiency pro¬ 
gram cost recovery—recovery of the direct costs associ¬ 
ated with program administration (including evaluation), 
implementation, and incentives to program participants. 
Reasonable opportunity for program cost recoyery is a 
necessary condition for utility program spending. Failure 
to recover these costs produces a direct dollar-for-dollar 
reduction in utility earnings, and discourages further 
investment. If, for whatever reason, a utility is unable 
to recover $500,000 in costs associated with an energy 
efficiency program, it will see a $500,000 drop in its net 
margin. 

Policies directing utilities to undertake energy efficiency 
programs in most cases authorize utilities to seek re¬ 
covery of program costs, even though actual recovery 
of all costs is never guaranteed. 3 Clarity with respect to 


the cost recovery process is critical, as broad uncertainty 
regarding the timing and threshold burden of proof 
can itself constitute almost as much a disincentive to 
utility investment as actual refusal to allow recovery of 
program costs. 4 A reasonable and reliable system of 
program cost recovery, therefore, is a necessary first ele¬ 
ment of a policy to eliminate financial disincentives to 
utility investment in energy efficiency. 

Policy-makers have a wide variety of tools available to 
them to address cost recovery. These tools can have 
very different financial implications depending on the 
specific context. More important, history has shown 
that recovery is not, in fact, a given. Chapter 5 provides 
a more complete treatment of program cost recovery 
mechanisms. However, with respect to the broader 
policy context, several points are important to note 
here. All are related to risk. 

2.2.1 Prudence 

State regulatory commissions, as well as the governing 
boards of publicly and cooperatively owned utilities, 
have fundamental obligations to ensure that the costs 
passed along to ratepayers are just and reasonable and 
were prudently incurred. Sometimes commissions have 
found these costs to be appropriately born by share¬ 
holders (such as "image advertising") rather than rate¬ 
payers. Other times, costs are disallowed because they 
are considered "unreasonable" for the good or service 
procured or delivered. Finally, regulators and boards 
might determine that a certain activity would not have 
been undertaken by prudent managers and thus costs 
associated with the activity should not be recoverable 
from ratepayers. 

While within the scope of regulatory authority, 5 such 
disallowances can create some uncertainty and risk for 
utilities if the rules governing prudence and reasonable¬ 
ness are not clear. 6 Regulated industries traditionally 
have been viewed as risk averse, in part because with 
their returns regulated, risk and reward are not sym¬ 
metrical. Utilities that have been faced with significant 
disallowances tend to be particularly averse to incurring 
any cost that is not pre-approved or for which there is a 
risk that a particular expense will be disallowed. 


2-2 


Aligning Utility Incentives with Investment in Energy Efficiency 


Program cost recovery requires a negotiation between 
regulators and utilities to create more certainty re¬ 
garding prudence and reasonableness and therefore, 
to assure utilities that energy efficiency costs will be 
recoverable. Many states provide this balance by requir¬ 
ing utilities to submit energy efficiency portfolio plans 
and budgets for review and sometimes approval. 7 The 
utility receives assurance that its proposed expenditures 
are decisionally prudent, and regulators are assured 
that proposed expenditures satisfy policy objectives. 

Such pre-approval processes do not preclude regulatory 
review of actual expenditures or findings that actual 
program implementation was imprudently managed. 

2.2.2 The Timing of Cost Recovery 

Cost recovery timing is important for two reasons: 

1. If there is a significant lag between a utility's expen¬ 
diture on energy efficiency programs and recovery of 
those costs, the utility incurs a carrying cost—it must 
finance the cash flow used to support the program 
expenditure. Even if a utility has sufficient cash flow 
to support program funding, these funds could have 
been applied to other projects were it not for the 
requirement to implement the program. 

2. The length of the time lag directly affects a utility's 
perception of cost recovery risk. The composition of 
regulatory commissions and boards changes fre¬ 
quently and while commissions may respect the deci¬ 
sions of their predecessors, they are not bound to 
them. Therefore, a change in commissions can lead 
to changes in or reversals of policy. More important, 
the longer the time lag, the greater the likelihood 
that unexpected events could occur that affect a 
utility's cash flow. 

The timing issues can be addressed in several ways. The 
two most prevalent approaches are to allow a utility 
to book program costs in a deferral account with an 
appropriate carrying charge applied, or to establish 
a tariff rider or surcharge that the utility can adjust 
periodically to reflect changes in program costs. Nei¬ 
ther approach precludes regulators from reviewing 
actual costs to determine reasonableness and making 


appropriate adjustments. However, the deferral ap¬ 
proach can create what is known as a regulatory asset, 
which can rapidly grow and, when it is added to the 
utility's cost of service, cause a jump in rates depending 
on how the asset is treated 8 

2.3 Lost Margin Recovery 

The objective of an energy efficiency program is to cost- 
effectively reduce consumption of electricity or natural 
gas. However, reducing consumption also reduces 
utility revenues and, under traditional rate designs that 
recover fixed costs through volumetric charges, lower 
revenues often lead to under-recovery of a utility's 
fixed costs. This, in turn, can lead to lower net operat¬ 
ing margins and profits and what is termed the "lost 
margin" effect. This same effect can create an incentive 
in certain cases for utilities to try to increase sales and 
thus, revenues, between rate cases—this is known as 
the throughput incentive. Because fixed costs (includ¬ 
ing financial margins) are recovered through volumetric 
charges, an increase in sales can yield increased earn¬ 
ings, as long as the costs associated with the increased 
sales are not climbing as fast. 

Treatment of lost margin recovery, either in a limited 
fashion or through some form of what is known as "de¬ 
coupling, " raises basic issues of not only what the regu¬ 
latory obligation is with regard to utility earnings, but 
also of the regulators' role in determining the utility's 
business model. Few energy efficiency policy issues have 
produced as much debate as the issue of the impact of 
energy efficiency programs on utility margins (Costello, 
2006; Eto et al., 1994; National Action Plan for Energy 
Efficiency, 2006b; Sedano, 2006). 

2.3.1 Defining Lost Margins 

The lost margin effect is a direct result of the way that 
electricity and natural gas prices are set under tradi¬ 
tional regulation. And while the issue might be more 
immediate for investor-owned utilities where profits are 
at stake, the root financial issues are the same whether 
the utility is investor-, publicly, or cooperatively owned. 


National Action Plan for Energy Efficiency 


2-3 


T 


Defining Terms 


A variety of terms are used to describe the financial effect of a reduction in utility sales caused by energy effi¬ 
ciency. All of these relate to the practice of traditional ratemaking, wherein some portion of a utility's fixed costs 
are recovered through a volumetric charge. Because these costs are fixed, higher-than-expected sales will lead to 
higher-than-expected revenue and possible over-recovery of fixed costs. Lower-than-expected sales will lead to un¬ 
der-recovery of these costs. The terminology used to describe the phenomenon and its impacts can be confusing, 
as a variety of different terms are used to describe the same effect. Key terms include: 

• Throughput —utility sales 

• Throughput incentive —the incentive to maximize sales under volumetric rate design. 

i 

• Throughput disincentive —the disincentive to encourage anything that reduces sales under traditional 
volumetric rate design. 

• Fixed-cost recovery —the recovery of sufficient revenues to cover a utility's fixed costs. 

• Lost revenue —the reduction in revenue that occurs when energy efficiency programs cause a drop in sales 
below the level used to set the electricity or gas price. There generally also is a reduction in cost as sales 
decline, although this reduction often is less than revenue loss. 

• Lost margin —the reduction in revenue to cover fixed costs, including earnings or,profits in the case of 
investor-owned utilities. Similar to lost revenue, but concerned only with fixed-cost recovery, or with the op¬ 
portunity costs of lost margins that would have been added to net income or created a cash buffer in excess of 
that reflected in the last rate case. The amount of margin that might be lost is a function of both the change in 
revenue and the any change in costs resulting from the change in sales. 

The National Action Plan for Energy Efficiency used throughput incentive to describe this effect. Where possible, 
this Report will also use that phrase. It will also describe the effect using the phrases under-recovery of margin 
revenue or lost margins, for the most part to describe issues related to the effect of energy efficiency on recovery 
of fixed costs. 


Traditional cost-of-service ratemaking is based on the 
same simple arithmetic used in Table 2-1 9 

average price = revenue requirement/ 
estimated sales 10 

revenue requirement = variable costs + depreci¬ 
ation + other fixed costs 
+ (capital costs x rate of 
return) 

revenue = actual sales x average 
price 

Capital costs are equal to the original cost of plant and 
equipment used in the generation, transmission, and 
distribution of energy, minus accumulated depreciation. 


The rate of return, in the case of an investor-owned 
utility, is a weighted blend of the interest cost on the 
debt used to finance the plant and equipment and an 
ROE that represents the return to shareholders. The dol¬ 
lar value of this ROE generally represents allowed profit 
or "margin." Publicly and cooperatively owned utilities 
do not earn profit per se, and so the rate of return for 
these enterprises is the cost of debt. 11 The sum of de¬ 
preciation, other fixed costs (e.g., fixed O&M, property 
taxes, labor), and the dollar return on invested capital 
represents a utility's total fixed costs. 

If actual sales fall below the level estimated when rates 
are set, the utility will not collect revenue sufficient to 
match its authorized revenue requirement. The portion 


2-4 


Aligning Utility Incentives with Investment in Energy Efficiency 



» 





Table 2-1. The Arithmetic of Rate-Setting 


Baseline 
(rate setting 
proceeding) 

Case 1 

(2% reduction 
in sales) 

Case 2 

(2% increase 
in sales) 

1. Variable costs 

i 

$1,000,000 

$980,000 

$1,020,000 

2. Depreciation + other fixed costs 

$500,000 

$500,000 

$500,000 

i 

3. Capital cost 

$5,000,000 

$5,000,000 

$5,000,000 

4. Debt 

$3,000,000 

$3,000,000 

$3,000,000 

5. Interest (@10%) 

$300,000 

$300,000 

$300,000 

6. Equity 

$2,000,000 

$2,000,000 

$2,000,000 

7. Rate of return on equity (ROE@ 10%) 

10% 

10% 

10% 

8. Authorized earnings 

$200,000 

$200,000 

$200,000 

9. Revenue requirement (1+2+5+8) 

$2,000,000 

$1,980,000 

$2,020,000 

* 

10. Sales (kWh) 

20,000,000 

19,600,000 

20,400,000 

11. Average price (9+10) 

$0.10 

$0,101 

$0.99 

12. Earned revenue (11x10) 

$2,000,000 

$1,960,000 

$2,040,000 

13. Revenue difference (12-9) 

0 

-$40,000 

+$40,000 

14. % of authorized earnings (13+8) 

0 

-20% 

+20% 


Note: Sample values used to illustrate the arithmetic of rate-setting. 


of the revenue requirement most exposed is a utility's 
margin. For legal and financial reasons, a utility will use 
available revenues to cover the costs of interest, depre¬ 
ciation, property taxes, and so forth, with any remaining 
revenues going to this margin, representing profit for an 
investor-owned utility. 12 - 13 

If sales rise above the levels estimated in a rate-setting 
process, a utility will collect more revenue than required 


to meet its revenue requirement, and the excess above 
any increased costs will go to higher earnings. 14 Table 
2-1 provides an example based on an investor-owned 
utility, and Chapter 4 of the Action Plan—the Business 
Case for Energy Efficiency—provides a very clear illustra¬ 
tion of this impact under a variety of scenarios. The 
results illustrated are sensitive to the relative proportion 
of fixed and variable costs in a utility's cost of ser¬ 
vice. The higher the proportion of the variable costs, 


National Action Plan for Energy Efficiency 


2-5 


























the lower the impact of a drop in sales. A gas utility's 
cost-of-service typically will have a higher proportion of 
fixed costs than an electric utility's and, therefore, the 
gas utility can be more financially sensitive to changes in 
sales relative to a test year level. 15 

This example only examines the impact on earnings due to 
a sales-produced change in revenue. Margins obviously also 
are affected by costs, and while many costs are consid¬ 
ered fixed in the sense that they do not vary as a function 
of sales, they are under the control of utilities. Therefore, 
increases in sales and revenue above a test year level do not 
necessarily translate into higher margins, and the impact of 
a reduction in sales on margins depends on how a utility 
manages its costs. / 

Although the revenue difference appears small, it can 
be significant due to the effects on financial margins. 
The Case 1 revenue deficit of $40,000 represents 20 
percent of the allowed ROE. In other words, a 2 percent 
drop in sales below the level assumed in the rate case 
translates into a 20 percent drop in earnings or margin, 
all else being equal. Similarly, sales that are 2 percent 
higher than assumed yield a 20 percent increase in 
earnings above authorized levels. 

The magnitude of the impact is, in this example, di¬ 
rectly related to the efficacy of the efficiency program. 
Many other factors can have a similar impact on util¬ 
ity revenues—for instance, sales can vary greatly from 
the rate case forecast assumptions due to weather or 
economic conditions in the utility's service territory. But 
unlike the weather or the economy, energy efficiency is 
the most important factor affecting sales that lies within 
the utility's control or influence, and successful energy 
efficiency programs can reduce sales enough to create a 
disincentive to engage in such programs. 

In Case 2, actual sales exceed estimated levels. Once 
rates are set, a utility may have a financial incentive to 
encourage sales in excess of the level anticipated during 
the rate-setting process, since additional units of energy 
sold compensate for any unanticipated increased costs, 
and may improve earnings. 16 


Chapter 5 explores mechanisms that can be used to ad¬ 
dress both cases. Generally, two approaches have been 
used,. First, several states have implemented what are 
termed lost revenue adjustment mechanisms (LRAMs) 
that attempt to estimate the amount of fixed-cost or 
margin revenue that is "lost" as a result of reduced 
sales. The estimated lost revenue is then recovered 
through an adjustment to rates. The second approach 
is known generically as "decoupling." A decoupling 
mechanism weakens or eliminates the relationship be¬ 
tween sales and revenue (or more narrowly, the revenue 
collected to cover fixed costs) by allowing a utility to 
adjust rates to recover authorized revenues independent 
of the level of sales. Decoupling actually can take many 
forms and include a variety of adjustments. 

LRAM and decoupling not only represent alternative ap¬ 
proaches to addressing the lost margins effect, but they 
also reflect two different policy questions related to the 
relationship between utility sales and profits. 

Provide compensation for lost margins? 

Should a utility be compensated for the under-recovery 
of allowed margins when energy efficiency programs— 
or events outside of the control of the utility, such as 
weather or a drop in economic activity—reduce sales 
below the level on which current rates are based? The 
financial implication—with all else being held equal— 
is easy to illustrate as shown in Table 4-1. In practice, 
however, determining what is lost as a direct result of 
the implementation of energy efficiency programs is 
not so simple. The determination of whether this loss 
should stand alone or be treated in context of all other 
potential impacts on margins also can be challeng¬ 
ing. For example, during periods between rate cases, 
revenues and costs are affected by a wide variety of 
factors, some within management control and some 
not. The impacts of a loss of revenue due to an energy 
efficiency program could be offset by revenue growth 
from customer growth or by reductions in costs. On the 
other hand, the addition of new customers imposes 
costs which, depending on rate structure, can exceed 
incremental revenues. 


2-6 


Aligning Utility Incentives with Investment in Energy Efficiency 


Change the basic relationship between sales 
and profit? 

Should lost margins be addressed as a stand-alone 
matter of cost recovery, or should they be considered 
within a policy framework that changes the relationship 
between sales, revenues, and margins—in other words 
by decoupling revenues from sales? Decoupling not 
only addresses lost margins due to efficiency program 
implementation. It also removes the incentive a utility 
might otherwise have to increase throughput, and can 
reduce resistance to policies like efficient building codes, 
appliance standards, and aggressive energy efficiency 
awareness campaigns that would reduce throughput. 

Decoupling also can have a significant impact on both 
utility and customer risk. For example, by smoothing 
earnings over time, decoupling reduces utility financial 
risk, which some have argued can lead to reductions 
in the utility's cost-of-capital. (For a discussion of this 
issue, see Hansen, 2007, and Delaware PSC, 2007.) 
Depending on precisely how the decoupling mechanism 
is structured, it can shift some risks associated with sales 
unpredictability (e.g., weather, economic growth) to 
consumers. 17 This is a design decision within the control 
of policy-makers, and not an inherent characteristic of 
decoupling. The issue of the effect of decoupling on risk 
and therefore, on the cost-of-capital, likely will receive 
greater attention as decoupling increasingly is pursued. 
The existing literature and current experience is incon¬ 
clusive, and the policy discussion would benefit from a 
more complete examination of the issue than is possible 
in this Report. 

Ultimately, the policy choice must be made based on 
practical considerations and a reasonable balancing of 
interests and risks. Most observers would agree that 
significant and sustained investment in energy efficiency 
by utilities, beyond that required by statute or order, will 
not occur absent implementation of some type of lost 
margin recovery mechanism. More important, a policy 
that hopes to encourage aggressive utility investment 
in energy efficiency most likely will not fundamentally 
change utility behavior as long as utility margins are 
directly tied to the level of sales. The increasing number 
of utility commissions investigating decoupling is clear 


evidence that this question has moved front and center 
in development of energy efficiency investment policies 
across the country. 

2.4 Performance Incentives 

The first two financial impacts described above pertain 
to obvious disincentives for utilities to engage in energy 
efficiency program investment. The third effect concerns 
incentives for utilities to undertake such investment. Full 
recovery of program costs and collection of allowed rev¬ 
enue eliminates potential financial penalties associated 
with funding energy efficiency programs. However, sim¬ 
ply eliminating financial penalties will not fundamentally 
change the utility business model, because that model 
is premised on the earnings produced by supply-side 
investment. In fact, the earnings inequality between 
demand- and supply-side investment even where pro¬ 
gram costs and lost margins are addressed can create a 
significant barrier to aggressive investment in energy ef¬ 
ficiency. An enterprise organized to focus on and profit 
by investment in supply is not easily converted to one 
that is driven to reduce demand. This is particularly true 
in the absence of clear financial incentives or funda¬ 
mental changes in the business environment. 18 

This issue is fundamental to a core regulatory func¬ 
tion—balancing a utility's obligation to provide service 
at the lowest reasonable cost and providing utilities the 
opportunity to earn reasonable returns. For example, 
assume that an energy efficiency program can satisfy 
an incremental resource requirement at half the cost 
of a supply-side resource, and that in all other financial 
terms the efficiency program is treated like the supply 
resource. Cost recovery is assured and lost margins are 
addressed. In this case, the utility will earn 50 percent 
of the return it would earn by building the power 
plant. Consumers as a whole clearly would be better 
off by paying half as much for the same level of energy 
service. However, the utility's earnings expectations are 
now changed, with a potential impact on its stock price, 
and total returns to shareholders could decline. There 
could be additional benefits, to the extent that inves¬ 
tors perceive the utility less vulnerable to fuel price or 


National Action Plan for Energy Efficiency 


2-7 



climate risk, but under the conventional approach to 
valuing businesses, the utility would be less attractive. 
This is an extreme example, and it is more likely that this 
trade-off plays out more modestly over a longer period 
of time. Nevertheless, the prospective loss of earnings 
from a shift towards greater reliance on demand-side 
resources is a concern among investor-owned utilities, 
and it will likely influence some utilities' perspective on 
aggressive investment in energy efficiency. 19 

The importance of performance incentives is not uni¬ 
versally accepted. Some parties will argue that utili¬ 
ties are obligated to pursue energy efficiency if that is 
the policy of the State. Those taking this view will see 
performance incentives as requiring customers to pay 
utilities to do something that should be done anyway. 
Others have argued that the basic business of a utility 
is to deliver energy, and that providing financial incen¬ 
tives over-and-above what could be earned by efficient 
management of the supply business simply raises the 
cost of service to all customers and distorts manage¬ 
ment behavior. 

Those holding this latter view often prefer that energy 
efficiency investment be managed by an independent 
third-party (see, for example, ELCON, 2007). Existing 
third-party models, such as those in Oregon, Vermont, 
and Wisconsin, have received generally high marks, 
but these models carry a variety of implications beyond 
those related to lost margins and performance incen¬ 
tives. Policy-makers interested in a third party model 
must balance the potentially beneficial effects for 
ratepayers with what is typically a lower level of control 
over the third party, and increased complexity in inte¬ 
grating supply- and demand-side resource policy. 

Apart from this threshold issue, regulators face a 
variety of options for providing incentives to utilities 
(see Chapter 7), ranging from mechanisms that tie a 
financial reward to specific performance metrics, includ¬ 
ing savings, to options that enable a sharing of program 
benefits, to rewards based on levels of program spend¬ 
ing. 20 The latter type of mechanism, while sometimes 
derided as an incentive to spend, not save, has been 


applied in some cases simply because it is easier to 

i 

develop and implement, and it can be combined with 
pre- and post-implementation reviews to ensure that 
ratepayer funds are being used effectively. 

Providing financial incentives to a utility if it performs 
well in delivering energy efficiency potentially can 
change the existing utility business model by making 
efficiency profitable rather than merely a break-even 
activity. Today such incentives are the exception rather 
than the norm. For example, California policy-makers 
have acknowledged that successfully reorienting utility 
resource acquisition policy to place energy efficiency 
first in the resource "loading order" requires that per¬ 
formance incentives be re-instituted (see CPUC, 2006). 

2.5 Linking the Mechanisms 

Each of the financial effects suggests a different potential 
policy response, and policy-makers can and have ap¬ 
proached the challenge in a variety of ways. It is the net 
financial effect of a package of cost recovery and incen¬ 
tive policies that matters in devising a policy framework to 
stimulate greater investment in energy efficiency. A variety 
of policy combinations can yield roughly the same effect. 
However, to the extent that mechanisms are developed to 
address all financial effects, care must be taken to ensure 
that the interactions among these are understood. 

The essential foundation of the policy framework is 
program cost recovery. While confidence in its ability to 
recover these direct costs is central to a utility's willing¬ 
ness to invest in energy efficiency, a number of options 
are available for recovery, some of which also address 
lost margins and performance incentives. Some states 
directly provide for lost margin recovery for losses due 
to efficiency programs through a decoupling or LRAM 
while others create performance incentive policies that 
indirectly compensate for some or all lost margins. Min¬ 
nesota, for example, abandoned its lost margin recovery 
mechanism in favor of a performance incentive after 
finding that levels of margin recovery had become so 
large that their recovery could not be supported by the 


2-8 


Aligning Utility Incentives with Investment in Energy Efficiency 


Figure 2-1. Linking Cost Recovery, 
Recovery of Lost Margins, and 
Performance Incentives 


Expense 
Rate case 
rider 


Lost revenue 

adjustment 

mechanism 



commission. Although it has been difficult to determine 
the precise impact of the change in policy, the utilities 
in Minnesota have indicated that they are generally 
satisfied given that prudent program cost recovery is 
guaranteed and significant performance incentives are 
available . 21 ' 22 Finally, the combination of program cost 
recovery and a decoupling mechanism could create a 
positive efficiency investment environment, even absent 
performance incentives. Depending on its structure, a 
decoupling mechanism can create more earnings stabil¬ 
ity, which, all else being equal, can reduce risk. 23 


2.6 "The DNA of the Company:" 
Examining the Impacts of 
Effective Mechanisms on the 
Corporate Culture 

A policy that addresses all three financial effects will, in 
theory, have a powerful impact on utility behavior and, 
ultimately, corporate culture, turning what for many 
utilities is a compliance function into a key element of 
business strategy. 24 Perhaps the clearest example of this 
is Pacific Gas & Electric. 


PG&E has one of the richest histories of investment in 
energy efficiency of any utility in the country, dating 
to the late 1970s. A vital part of that history has been 
California's policy with respect to program cost recovery, 
treatment of fixed-cost recovery and performance in¬ 
centives. Decoupling, in the form of electric rate adjust¬ 
ment mechanism (ERAM), was instituted in 1982. ERAM 
was suspended as the state embarked on its experiment 
with utility industry restructuring. While that specific 
mechanism has not been reinstituted, 2001 legisla¬ 
tion effectively required reintroduction of decoupling, 
which each investor-owned utility has pursued, though 
in slightly different forms. Similarly, utility performance 
incentives were authorized more than a decade ago, 
but were suspended in 2002 amidst of a broad rethink¬ 
ing of the administrative structure for energy efficiency 
investment in the State. A September 2007 decision 
by the California Public Utilities Commission (CPUC), 
reinstated utility performance incentives through an in¬ 
novative risk/reward mechanism offering utilities collec¬ 
tively up to $450 million in incentives over a three-year 
period. At the same time, this mechanism will impose 
penalties on utilities for failing to meet performance tar¬ 
gets (see Section 7.3 for a more complete description). 

The policy framework in California supports very ag¬ 
gressive investment in energy efficiency, placing energy 
efficiency first in the resource loading order through 
adoption of the state's Energy Action Plan. The Energy 
Action Plan also established that utilities should earn 
a return on energy efficiency investments commensu¬ 
rate with foregone return on supply-side assets. Public 
proceedings directed by CPUC set three-year goals for 
each utility, and the payment of performance incentives 
will be based on meeting these goals. 

PG&E's current energy efficiency investment levels are 
approaching an all-time high, totaling close to $1 billion 
over the 2006-2008 period. Base funding comes from 
the state's public goods charge, but a substantial frac¬ 
tion now comes as the result of the State's equivalent 
of integrated resource planning proceedings. These 
procurement proceedings, through which the loading 
order is implemented, will continue to maintain energy 


National Action Plan for Energy Efficiency 


2-9 



X 


efficiency funding at levels in excess of the public goods 
charge, as the state pursues aggressive savings goals. 

A view only to savings targets and spending levels 
might suggest that a discussion of disincentive to invest¬ 
ment and utility corporate culture is irrelevant in PG&E's 
case. However, support for these aggressive investments 
appears to be run deep within the California investor- 
owned utilities, and clearly this policy would struggle 
were it not for utility support. Even so, has this policy 
actually shaped utility corporate culture? 

Discussions with PG&E management suggest the 
answer is "yes" (personal communication with Roland 
Risser, Director of Customer Energy Efficiency, Pacific 
Gas & Electric Company, May 2, 2007). Although 
investment levels always have been high in absolute 
terms, the company's view in the 1980s initially had 
been that, as long as energy efficiency investment did 
not hurt financially, the company would not resist that 
investment. However, the combined effect of ERAM and 
utility performance incentives turned what had been a 
compliance function into a vital piece of the company's 
business, and a defining aspect of corporate culture 
that has produced the largest internal energy efficiency 
organization in the country. 25 

The policy and financial turbulence created by the 
state's attempt at industry restructuring challenged this 
culture, first as ERAM and performance incentives were 
halted, and then as the regulatory environment turned 
sour with the energy crisis. However, a combination of 
a new policy recommitment to demand-side manage¬ 
ment (DSM), and the arrival of a new PG&E CEO have 
combined to reset the context for utility investment in 
efficiency and strengthen corporate commitment. De¬ 
coupling is again in place and CPUC has adopted a new 
performance incentive structure. 

The significant escalation in efficiency funding driven by 
California's Energy Action Plan, in addition to resource 
procurement proceedings, required the company to 
address the role of energy efficiency investment in more 
fundamental terms internally. The choices made in the 
procurement proceedings allocated funding to energy 


efficiency resources—funding that otherwise would 
have gone to support acquisition of conventional sup¬ 
ply. While in most organizations such allocation pro¬ 
cesses can create fierce competition, the environment 
within PG&E has significantly reduced potential conflict 
and even more firmly embedded energy efficiency in 
the company's clean energy strategy. 

The culture shift certainly is the product of a combina¬ 
tion of forces, including the arrival of a new CEO with a 
strong commitment to climate protection; a state policy 
environment that is intensely focused on clean energy 
development; an investment community interested in 
how utilities hedge their climate risks; and the re-emer¬ 
gence of favorable treatment of fixed-cost coverage and 
performance incentives. It is not clear that progressive 
cost recovery and incentive policies are solely respon¬ 
sible for this change, but without these policies it is 
unlikely that efficiency investment would have become 
a central element of corporate strategy, embedded "in 
the DNA of the Company" (personal communication with 
Roland Risser, PG&E). 

Would the same cost recovery and incentive structure have 
the same effect elsewhere? That answer is unclear, though 
it is unlikely that simply adopting mechanisms similar to 
what are in place in California would effect overnight 
change. Corporate culture is formed over extended peri¬ 
ods of time and is influenced by the whole of an operating 
environment and the leadership of the company. Never¬ 
theless, according to senior PG&E staff, the effect of the 
cost recovery and incentive policies is undeniable—in this 
case it was the catalyst for the change. 

2.7 The Cost of Regulatory Risk 

A comprehensive cost recovery and incentive policy can 
help institutionalize energy efficiency investment within 
a utility. At the same time, the absence of a compre¬ 
hensive approach, or the inconsistent and unpredictable 
application of an approach, can create confusion with 
respect to regulatory policy and institutionalize resis¬ 
tance to energy efficiency investment. A significant risk 
that policy-makers could disallow recovery of program 


2-10 


Aligning Utility Incentives with Investment in Energy Efficiency 



costs and/or collection of incentives, even if such invest¬ 
ments have been encouraged, imposes a real, though 
hard-to-quantify cost on utilities. While a significant 
disallowance can have direct financial implications, a 
less tangible cost is associated with the institutional fric¬ 
tion a disallowance will create. Organizational elements 
within a utility responsible for energy efficiency initia¬ 
tives will find it increasingly difficult to secure resources. 
Programs that are offered will tend to be those that 
minimize costs rather than maximize savings or cost- 
effectiveness. Easing this friction will not be as simple as 
a regulatory message that it will not happen again, and 
in fact the disallowance could very well have been justi¬ 
fied, should have happened, and would happen again. 

Regulators clearly cannot give up their authority and 
responsibility to ensure just and reasonable rates based 
on prudently incurred costs. And changes in the course 
of policy are inevitable, making flexibility and adaptabil¬ 
ity essential. All parties must realize, however, that the 
consistent application of policy with respect to cost re¬ 
covery and incentives matters as much if not more than 
the details of the policies themselves. The wide variety 
of cost recovery and incentive mechanisms provides 
opportunities to fashion a similar variety of workable 
policy approaches. Significant and sustained investment 
in energy efficiency by utilities very clearly requires a 
broad and firm consensus on investment goals, strategy, 
investment levels, measurement, and cost recovery. It is 
this consensus that provides the necessary support for 
consistent application of cost recovery and incentives 
mechanisms. 26 

I 

2.8 Notes 

1. However, as they explored industry restructuring, a number of 
states stripped utility commissions of regulatory authority over 
generation and, in some cases, transmission to varying degrees. 

2. In fact, many gas utilities do make investment in plant and equip¬ 
ment beyond gas distribution pipes—gas peaking and storage 
facilities, for example. 

3. Recovery of costs always is based on demonstration that the costs 
were prudently incurred. 

4. The forward period for which energy efficiency program costs 


is approved can be quite important to the success of programs. 
Year-by-year approval requirements complicate program plan¬ 
ning, and longer term commitments to the market actors cannot 
be made. The trend among states is to move toward longer 
program implementation periods, e.g., three years. Thus, to the 
extent that program costs are reviewed as part of proposed im¬ 
plementation plans, initial approval for spending is conferred for 
the three-year period, providing program stability and flexibility. 

5. Courts can rule on appeal that regulatory disallowances were not 
supported by the facts of a case or by governing statute. 

6. In fact, some such disallowances have had the effect of clarifying 
these rules. 

7. Another approach to achieving this balance is using stakeholder 
collaboratives to review, help fashion, and, where appropriate 
based on this review, endorse certain utility decisions. Where 
these collaboratives produce stipulations that can be offered to 
regulators, they provide some additional assurance to regula¬ 
tors that parties who might otherwise challenge the prudence or 
reasonableness of an action, have reviewed the proposed action 
and found it acceptable. Though sometimes time-and resource¬ 
intensive, such collaboratives have been helpful tools for reducing 
utility prudence risk related to energy efficiency expenditures. 

8. In addition, because such regulatory asset accounts are backed 
not by hard assets but by a 1 regulatory promise to allow recovery, 
their use can raise concern in the financial community particularly 
for utilities with marginal credit ratings. 

9. The lost margin issue actually arises as a function of rate designs 
that intend to recover fixed costs through volumetric (per kilo¬ 
watt-hour or therm) charges. A rate design that placed all fixed 
costs of service in a fixed charge per customer (SFV rate) would 
largely alleviate this problem. However such rates significantly re¬ 
duce a consumer's incentive to undertake efficiency investments, 
since energy use reductions would produce much lower customer 
bill savings relative to a the situation under a rate design that 
included fixed costs in volumetric charges. In addition, fixed- 
variable rates are criticized as being regressive (the lower the 
use, the higher the average cost per unit consumed) and unfair 
to low-income customers. See Chapter 5, "Rate Design," of the 
Action Plan for an excellent discussion of this process. 

10. This equation is a simplification of the rate-setting process. The 
actual rates paid per kilowatt-hour or therm often will be higher 
or lower than the average revenue per unit. 

11. Note, however, that publicly owned utilities typically must transfer 
some fraction of net operating margins to other municipal funds, 
and cooperatively owned utilities typically pay dividends to the 
member of the co-op. These payments are the practical equiva¬ 
lent of investor-owned utility earnings. In addition, these utilities 
typically must meet bond covenants requiring that they earn 
sufficient revenue to cover a multiple of their interest obligations. 
Therefore, there can be competing pressures for publicly and 
cooperatively owned utilities to maintain or increase sales at the 
same time that they promote energy efficiency programs. 


National Action Plan for Energy Efficiency 


2-11 


12. Although a utility is not obligated to pay returns to shareholders 
in the same sense that it is obligated to pay for fuel or to pay 
the interest associated with debt financing, failure to provide the 
opportunity to earn adeguate returns will lead equity investors 
to view the utility as a riskier or less desirable investment and will 
require a higher rate of return if they are to invest in the utility. 
This will increase the utility's overall cost of service and its rates. 

13. Publicly and cooperatively owned utilities do not earn profits per 
se and thus, have no return on equity. However, they do earn 
financial margins calculated as the difference between revenues 
earned and the sum of variable and fixed costs. These margins 
are important as they fund cooperative member dividends and 
payments to the general funds of the entities owning the public 
utilities. 

14. The actual impact on margins of a change in sales depends criti¬ 
cally on the extent to which fixed costs are allocated to volu- 
metric charges. Actual electricity and natural gas prices usually 
include both a fixed customer charge and a price per unit of 
energy consumed. The larger the share of fixed costs included in 
this price per unit, the more a utility's margin will fluctuate with 
changes in sales. 

15. A gas utility's cost of service does not include the actual com¬ 
modity cost of gas which is flowed through directly to customers 
without mark-up. 

16. Some states require utilities to participate in a rate case every two 
or three years. Others hold rate cases only when a utility believes 
it needs to change its prices in light of changing costs or the 
regulatory agency believes that a utility is over-earning. 

17. Unless properly structured, a decoupling mechanism also can lead 
to a utility over-earning—collecting more margin revenue than it 
is authorized to collect. 

18. An alternative has been for state utility commissions to require 
adherence to least-cost planning principles that require the less 
expensive energy efficiency to be "built," rather than the new 
supply-side resource. However, this approach does not alter the 
basic financial landscape described above. 

19. The California Public Utilities Commission's recent ruling regard¬ 
ing utility performance rewards explicitly recognized this issue. 


20. The actual implementation of an incentive mechanism may ad¬ 
dress more than financial incentives. For example, The Minnesota 
Commission considers its financial incentive mechanism as effec¬ 
tively addressing the financial impact of the reduction in revenue 
due to an energy efficiency program. 

21. State EE/RE Technical Forum Call #8, Decoupling and Other 
Mechanisms to Address Utility Disincentives for Implementing En¬ 
ergy Efficiency, May 19, 2005. <http://www.epa.gov/cleanenergy/ 
stateandlocal/efficiency.htm#decoup> 

22. The Minnesota Legislature recently adopted legislation directing 
the Minnesota Public Service Commission to adopt criteria and 
standards for decoupling, and to allow one or more utilities to 
establish pilot decoupling programs. S.F. No. 145, 2nd Engross¬ 
ment 85th Legislative Session (2007-2008). 

23. As noted, some argue that this risk reduction should translate 
into a corresponding reduction in the cost of capital, although 
views are mixed regarding the extent to which this reduction can 
be quantified. 

24. For a broader discussion of how cost recovery and incentive 
mechanisms can affect the business model for utility investment 
in energy efficiency, see NERA Economic Consulting (2007). Mak¬ 
ing a Business of Energy Efficiency: Sustainable Business Models 
for Utilities. Prepared for Edison Electric Institute. 

25. This infrastructure was significantly scaled back during California's 
restructuring era. 

26. One way to manage the regulatory risk issue is to make the 
regulatory goals very clear and long-term in nature. Setting en¬ 
ergy savings targets—for example, by using an Energy Efficiency 
Resource Standard—can remove some part of the utility's risk. If 
the utility meets the targets, and can show that the targets were 
achieved cost-effectively, prudence and reasonableness are easier 
to establish, and cost recovery and incentive payments become 
less of an issue. Otherwise, more issues are under scrutiny: did 
the utility seek "enough" savings? Did it pursue the "right" tech¬ 
nologies and markets? With a high-level, simple, and long-term 
target, such issues become less germane. 


2-12 


Aligning Utility Incentives with Investment in Energy Efficiency 


Understanding Objectives 
Developing Policy 
! Approaches That Fit 



This chapter explores a range of possible objectives for policy-makers' consideration when exploring 
policies to address financial disincentives. It also addresses the broader context in which these objectives 
are pursued. 


3.1 Potential Design Objectives 

Each jurisdiction could value the objectives of the 
energy efficiency investment process and the objectives 
of cost recovery and incentive policy design differently. 
Jurisdictional approaches are formed by a variety of 
statutory constraints, as well as by the ownership and 
financial structures of the utilities; resource needs; and 
related local, state, and federal resource and environ¬ 
mental policies. The overarching objective in every 
jurisdiction that considers an energy efficiency 
investment policy should be to generate and cap¬ 
ture substantial net economic benefits This broad 
objective sometimes is expressed as a spending target, 
but more often as an energy or demand reduction tar¬ 
get, either absolute (e.g., 500 MW by 2017) or relative 
(e.g., meet 10, 50, or 100 percent of incremental load 
growth or total sales). Increasingly, states are linking this 
objective to others that promote the use of cost-effec¬ 
tive energy efficiency as an environmentally preferred 
option. The objectives outlined below guide how a cost 
recovery and incentive policy is crafted to support this 
overarching objective. 

A review of the cost recovery and incentive literature, as 
well as the actual policies established across the country, 
reveals a fairly wide set of potential policy objectives. 

Each one of these is not given equal weight by policy¬ 
makers, but most of these are given at least some con¬ 
sideration in virtually every discussion of cost recovery 
and performance incentives. Many of these objectives 
apply to broader regulatory issues as well. Here the focus 
is solely on the objectives as they might apply to design 
of cost recovery and incentive mechanisms intended 


to serve the overarching objective stated above; that 
is whether the treatment of these objectives leads to a 
policy that effectively incents substantial cost-effective 
savings. A cost recovery and incentives policy that satis¬ 
fies each of the design objectives described below, but 
which does not stimulate utility investment in energy 
efficiency, would not serve the overarching objective. 

3.1.1 Strike an Appropriate Balance of Risk/ 
Reward Between Utilities/Customers 

The principal trade-off is between lowering utility risk/ 
enhancing utility returns on the one hand and the mag¬ 
nitude of consumer benefits on the other. Mechanisms 
that reduce utility risk by, for example, providing timely 
recovery of lost margins and providing performance in¬ 
centives, reduce consumer benefit, since consumers will 
pay for recovery and incentives through rates. 1 Howev¬ 
er, if the mechanisms are well-designed and implement¬ 
ed, customer benefits will be large enough that sharing 
some of this benefit as a way to reduce utility risk and 
strengthen institutional commitment will leave all parties 
better off than had no investment been made. 

3.1.2 Promote Stabilization of Customer Rates 
and Bills 

This objective is common to many regulatory policies 
and is relevant to energy efficiency cost recovery and 
incentives policy primarily with respect to recovery of 
lost margins. The ultimate objective served by a cost 
recovery and incentives policy implies an overall reduc¬ 
tion in the long run costs to serve load, which equate 
to the total amount paid by customers over time. 
Therefore, while it is prudent to explore policy designs 
that, among available options, minimize potential rate 


National Action Plan for Energy Efficiency 


3-1 



volatility, the pursuit of rate stability should be balanced 
against the broader interest of total customer bill reduc¬ 
tions. In fact, there are cases (Questar Gas in Utah, for 
example) where energy efficiency programs produce 
benefits for all customers (programs pass the so-called 
No-Losers test of cost-effectiveness) through reductions 
in commodity costs (Personal communication with Barry 
McKay, Questar Gas, July 9, 2007). 

Program costs and performance incentives are rela¬ 
tively stable and predictable, or at least subject to caps. 
Lost margins can grow rapidly, and recovery can have 
a noticeable impact on customer rates. Decoupling 
mechanisms can be designed to mitigate this problem 
through the adoption of annual caps, but there have 
been isolated cases in which the true-ups have become 
so large due to factors independent of energy efficiency 
investment that regulators have balked at allowing full 
recovery. 2 Therefore, consideration of this objective is 
important for customers and utilities, as erratic and 
substantial energy efficiency cost swings can imperil full 
recovery and increase the risk of efficiency investments 
for utilities. 

3.1.3 Stabilize Utility Revenues 

This objective is a companion to stabilization of rates. 
Aggressive energy efficiency programs will impact utility 
revenues and full recovery of fixed costs. However, even if 
cost recovery policy covers program costs, lost margins, and 
performance incentives, how this recovery takes place can 
affect the pattern of earnings. Large episodic jumps in earn¬ 
ings (for example, produced by a decision to allow recovery 
of accrued lost margins in a lump sum), while better than 
non-recovery, cloud the financial community's ability to 
discern the true financial performance of the company, and 
creates the perception of risk that such adjustments might 
or might not happen again. PG&E views the ability of its 
decoupling mechanism to smooth earnings as a very im¬ 
portant risk mitigation tool (personal communication with 
Roland Risser, PG&E). 


3.1.4 Administrative Simplicity and Managing 
Regulatory Costs 

Simplicity requires that any/all mechanisms be trans¬ 
parent with respect to both calculation of recoverable 
amounts and overall impact on utility earnings. This, in 
turn, supports minimizing regulatory costs. Given the 
workload facing regulatory commissions, adoption of 
cost recovery and incentive mechanisms that require 
frequent and complex regulatory review will create a 
latent barrier to effective implementation of the mecha¬ 
nisms. Every mechanism will impose some incremental 
cost on all parties, since some regulatory responsibilities 
are inevitable. The objective, therefore, is to structure 
mechanisms with several attributes that can establish at 
least a consistent and more formulaic process. 

The mechanism should be supported by prior regulatory 
review of the proposed efficiency investment plan, and 
at least general approval of the contours of the plan 
and budget. In the alternative, policy-makers can estab¬ 
lish clear rules prescribing what is considered accept¬ 
able/necessary as part of an investment plan, including 
cost caps. This will reduce the amount of time required 
for post-implementation review, as the prudence of the 
investment decision and the reasonableness of costs will 
have been established. 

Use of tariff riders with periodic true-up allows for more 
clear segregation of investment costs and adjustment 
for over/under-recovery than simply including costs in a 
general rate case. However, in some states, the periodic 
treatment of energy efficiency program costs, fixed cost 
recovery, and incentives outside of a general rate case 
could be prohibited as single-issue ratemaking. 3 

Because certain mechanisms require evaluation and 
verification of program savings as a condition for recov¬ 
ery, very clear specification of the evaluation standards 
at the front end of the process is important. Millions of 
dollars are at stake in such evaluations, and failure to 
prescribe these standards early in the process almost 
guarantees that evaluation methods will be contested in 
cost recovery proceedings. 


3-2 


Aligning Utility Incentives with Investment in Energy Efficiency 


3.2 The Design Context 

but what are the variables that determine the context 
for cost recovery and incentive design? Table 3-1 identi¬ 

The need to design mechanisms that match the often 
unique circumstances of individual jurisdictions is clear, 

fies and describes several variables often cited as impor¬ 
tant influences. 


Variable 

Implication 

Related to Industry Structure 


Differences between gas and electric utility policy and 
operating environments 

Wide variety of embedded implications. Gas util¬ 
ity cost structures create greater sensitivity to sales 
variability and recovery of fixed costs. In addition, as 
an industry, gas utilities face declining demand per 
customer. 

Differences between investor-, publicly, and coopera¬ 
tively owned utilities 

Significant differences in financing structures. Mu¬ 
nicipal and cooperative ownership structures might 
provide greater ratemaking flexibility. Shareholder 
incentives are not relevant to publicly and coopera¬ 
tively owned utilities, although management incen¬ 
tives might be. 

Differences between bundled and unbundled utilities 

Unbundled electric utilities have cost structures with 
some similarities to gas utilities; may be more suscep¬ 
tible to sales variability and fixed-cost recovery. 

Presence of organized wholesale markets 

Organized markets may provide an opportunity for utili¬ 
ties to resell "saved" megawatt-hours and megawatts to 
offset under-recovery of fixed costs. 

Related to Regulatory Structure and Process 


Utility cost recovery and ratemaking statutes and rules 

Determines permissible types of mechanisms. Pro¬ 
hibitions on single-issue ratemaking could preclude 
approval of recovery outside of general rate cases. 
Accounting rules could affect use of balancing and 
deferred/escrow accounts. Use of deferred accounts 
creates regulatory assets that are disfavored by Wall 
Street. 

Related legislative mandates such as DSM program 
funding levels or inclusion of DSM in portfolio 
standards 

Can eliminate decisional prudence issues/reduce utility 
program cost recovery risk. Does not address fixed- 
cost recovery or performance incentive issues. 


National Action Plan for Energy Efficiency 


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Table 3-1. Cost Recovery and Incentive Design Considerations (continued) 


Variable Implication 


Related to Regulatory Structure and Process (continued) 


Frequency of rate cases and the presence of automatic 
rate adjustment mechanisms 

Frequent rate cases reduce the need for specific fixed- 
cost recovery mechanism, but do not address utility 
incentives to promote sales growth or disincentives 
to promote customer energy efficiency. Utility and 
regulator costs increase with frequency. 

Type of test year 

Type of test year (historic or future) is relevant mostly 
in cases in which energy efficiency cost recovery takes 
place exclusively within a rate case. Test year costs 


typically must be known, which can pose a problem 
for energy efficiency programs that are expected to 
ramp-up significantly. This applies particularly to the 
initiation or significant ramp-up of energy efficiency 
programs combined with a historic test year. 

Performance-based ratemaking elements 

Initiating an energy efficiency investment program 
within the context of an existing performance-based 
ratemaking (PBR) structure can be complicated, requir¬ 
ing both adjustments in so-called "Z factors"4 and 
performance metrics. However, revenue-cap PBR can be 
consistent with decoupling. 

Rate structure 

The larger the share of fixed costs allocated to fixed 
charges, the lower the sensitivity of fixed-cost re¬ 
covery to sales reductions. Price cap systems pose 
particular issues, since costs incurred for programs 
implemented subsequent to the cap but prior to its 
expiration must be carried as regulatory assets with all 
of the associated implications for the financial evalu¬ 
ation of the utility and the ultimate change in prices 
once the cap is lifted. 

Regulatory commission/governing board resources 

Resource-constrained commissions/governing boards 
may prefer simpler, self-adjusting mechanisms. 

Related to the Operating Environment 


Sales/peak growth and urgency of projected reserve 
margin shortfalls 

Rapid growth may imply growing capacity needs, which 
will boost avoided costs. Higher avoided costs create a 
larger potential net benefit for efficiency programs and 
higher potential utility performance incentive. Growth 
rate does not affect fixed-cost recovery if the rate has 
been factored into the calculation of prices. 


3-4 


Aligning Utility Incentives with Investment in Energy Efficiency 















Table 3-1. Cost Recovery and Incentive Design Considerations (continued) 

Variable 

Implication 

Related to the Operating Environment (continued) 

Volatility in load growth 

Unexpected acceleration or slowing of load growth 
can have a major impact on fixed-cost recovery, an 
impact that can vary by type of utility. Higher than 
expected growth can lessen the impact of energy 
efficiency on fixed cost recovery, while slower growth 
exacerbates it. On the other hand, if the cost to add 
a new customer exceeds the embedded cost, higher 
than expected growth can adversely impact utility 
finances. 

Utility cost structure 

Utilities with higher fixed/variable cost structures are 
more susceptible to the fixed-cost recovery problem. 

Structure of the DSM portfolio 

Portfolios more heavily weighted toward electric 
demand response will result in less significant lost 
margin recovery issues, thus reducing the need for a 
specific mechanism to address. Moreover, a portfolio 
weighted toward demand response typically will not 
offer the same environmental benefits. 


negative impacts were exacerbated by accounting treatments 
that deferred recovery of the revenues in the balancing accounts. 

3. Single issue ratemaking allows for a cost change in a single item 
in a utility's cost of service to flow through to consumer rates. A 
prohibition on single-issue ratemaking occurs because, among 
the multitude of utility cost items, there will be increases and 
decreases, and many states find it inappropriate to base a rate 
change on the movement of any single cost item in isolation. In 
some states, a fuel adjustment clause is an exception to this rule, 
justified because the impacts of changes in fuel costs on the total 
cost of service is high. States that employ an energy efficiency 
rider justify this exception as a function of the policy importance 
of energy efficiency and as an important element in creating a 
stable energy efficiency funding environment. 

4. Z factors are factors affecting the price of service over which 
the utility has no control. PBR programs typically allow rate cap 
adjustments to accommodate changes in these factors. 


3.3 Notes 

1. A related concern raised by skeptics of performance incentives 
is that by providing an incentive to utilities to deliver success¬ 
ful energy efficiency programs, customers might pay more than 
they otherwise should or would have to achieve the same result 
if another party delivered the programs, or if the utilities were 
simply directed to acquire a certain amount of energy savings. Of 
course, the counter-argument is that in some cases, the level of 
savings actually achieved by a utility (savings in excess of a goal, 
for example) are motivated by the opportunity to earn an incen¬ 
tive. In addition, certain third-party models include the opportu¬ 
nity for the administering entity to earn performance incentives. 

2. See the discussion of the Maine decoupling mechanism in the 
National Action Plan for Energy Efficiency, July 2006, Chapter 2, 
pages 2-5. The examples of this issue are isolated, emerging 

in early decoupling programs in the electric utility industry. The 


National Action Plan for Energy Efficiency 


3-5 





















This chapter provides a practical overview of alternative cost recovery mechanisms and presents their 
pros and cons. Detailed case studies are provided for each mechanism. 


4.1 Overview 

Administration and implementation of energy efficiency 
programs by utilities or third-party administrators involves 
the annual expenditure of several million dollars to sever¬ 
al hundred million dollars, depending on the jurisdiction. 
The most basic requirement for elimination of disincen¬ 
tives to customer-funded energy efficiency is establishing 
a fair, expeditious process for recovery of these costs, 
which include participant incentives and implementation, 
administration, and evaluation costs. Failure to recover 
such costs directly and negatively affects a utility's cash 
flow, net operating income, and earnings. 

Utilities incur two types of costs in the provision of 
service. Capital costs are associated with the plant and 
equipment associated with the production and delivery 
of energy. Expenses typically are the costs of service 
that are not directly associated with physical plant or 
other hard assets. 1 The amount of revenue that a utility 
must earn over a given period to be financially viable 
must cover the sum of expenses over that period plus 
the financial cost associated with the utility's physical 
assets. In simple terms, a utility revenue requirement is 

I 

equivalent to the cost of owning and operating a home, 
including the mortgage payment and ongoing expens¬ 
es. The costs associated with utility energy efficiency 
programs must be recovered either as expenses or as 
capital items. 

The predominant approach to recovery of program costs is 
through some type of periodic rate adjustment established 
and monitored by state utility regulatory commissions or 
the governing entities for publicly or cooperatively owned 
utilities. These regulatory mechanisms can take a variety 
of forms including recovery as expenses in traditional rate 


cases, recovery as expenses through surcharges or rid¬ 
ers that can be adjusted periodically outside of a formal 
rate case, or recovery via capitalization and amortization. 
Variations exist within these broad forms of cost recovery 
as well, through the use of balancing accounts, escrow 
accounts, test years, and so forth. 

The approach applied in any given jurisdiction will often 
be the product of a variety of local factors such as the 
frequency of rate cases, the specific forms of cost ac¬ 
counting allowed in a state, the amount and timing of 
expenditures, and the types of programs being imple¬ 
mented. States will also differ in how costs are distribut¬ 
ed across and recovered from different customer classes. 
Some states, for example, allow large customers to opt- 
out of efficiency programs administered by utilities, 2 and 
some states require that costs be recovered only from the 
classes of customers directly benefiting from specific pro¬ 
grams. These variations preclude a single best approach. 
However, for those utilities and states considering imple¬ 
mentation of energy efficiency programs, the variety of 
approaches offers a variety of options to consider. 

4.2 Expensing of Energy 
Efficiency Program Costs 

Most energy efficiency program costs are recovered 
through "expensing." In the simplest case, if a utility 
spends $1.00 to fund an energy efficiency program, 
that $1.00 is passed directly to customers as part of the 
utility's cost of service. While in principle, the expensing 
of energy efficiency program costs is straightforward, 
utilities and state regulatory commissions have em¬ 
ployed a wide variety of specific accounting treatments 
and actual recovery mechanisms to enable recovery of 


National Action Plan for Energy Efficiency 


4-1 



program expenses. This section provides an overview of 
several of the more common approaches. 


4.2.1 Rate Case Recovery 

The most straightforward approach to recovery of pro¬ 
gram costs as expenses involves recovery in base rates 
as an element of the utility revenue requirement. Energy 
efficiency program costs are estimated for the relevant 
period, added to the utility's revenue requirement, and 
recovered through customer rates that were set based 
on this revenue requirement and estimated sales. Rate 
cases typically involve an estimate of known future 
costs, given that the rates that emerge from the case 
are applied going forward. For example, a utility and its 
commission might conduct a rate case in 2007 to estab¬ 
lish the rates that will apply beginning in 2008. There¬ 
fore, the utility will estimate (and be seeking approval 
to incur) the costs associated with the energy efficiency 
program in 2008 and annually thereafter. The approved 
level of energy efficiency spending will be included in 
the allowed revenue requirement, and the rates tak¬ 
ing effect in 2008 should include an amount that will 
recover the utility's budgeted program costs over the 
course of the year based on the level of annual sales 
estimated in the rate case. Although actual program 
expenses rarely match the amount of revenue collected 
for those programs in real-time, in principle, program 
expenses incurred will match revenue received by the 
end of the year. This approach works best when annual 
energy efficiency expenditures are constant on average. 


4.2.2 Balancing Accounts with Periodic True-Up 

Practice rarely matches principle, however, particularly 
with respect to energy efficiency program costs. The esti¬ 
mates of program costs used as the basis for setting rates 
are based in large part on assumed customer participa¬ 
tion in the efficiency programs. However, participation is 
difficult to predict at a level of precision that ensures that 
annual expenditures will match annual revenue, espe¬ 
cially in the early years of programs. Under-recovery of 
expenses occurs if participation in programs exceeds esti¬ 
mates and actual program costs rise. Regulatory commis¬ 
sions and utilities frequently have implemented various 
types of balancing mechanisms to ensure that customers 
do not pay for costs never incurred, and that utilities are 


not penalized because participation and program costs 
exceeded estimates. Such approaches also enable utilities 
to more flexibly ramp program activity (and associated 
spending) up or down. These mechanisms also often 
include some type of periodic prudence review to ensure 
that costs incurred in excess of those estimated in the 
rate case were prudently incurred. 

The mechanics of a balancing account can work in a 
number of ways. Balances can simply be carried (typically 
with an associated carrying charge) until the next rate 
case, at which point they are "trued-up." 3 A positive bal¬ 
ance could be used to reduce the level of expenses au¬ 
thorized for recovery in the future period, and a negative 
balance could be added in full to the authorized revenues 
for the future period or could be amortized. Alternatively, 
the balances can be self-adjusting by using a surcharge 
or tariff rider (discussed below), and some states allow 
annual true-up outside of general rate case proceedings. 4 

4.2.3 Pros and Cons 

Table 4-1 describes general pros and cons associated 
with the expensing of program costs. 

4.2.4 Case Study: Arizona Public Service 
Company (APS) 

In June 2003, APS filed an application for a rate in¬ 
crease and a settlement agreement was signed between 
APS and the involved parties in August 2004. The settle¬ 
ment addresses DSM and cost recovery, allowing $10 
million each year in base rates for eligible expenses, as 
well as an adjustment mechanism for program expenses 
beyond $10 million. 

• The settlement agreement embodied in Order No. 
67744 issued in April of 2005, under Docket No. E- 
01345A-03-0437 5 includes the following provisions: 

• Included in APS' total test year settlement base rate 
revenue requirement is an annual $10 million base 
rate DSM allowance for the costs of approved "eli¬ 
gible DSM-related items," defined as the planning, 
implementation, and evaluation of programs that 
reduce the use of electricity by means of energy ef¬ 
ficiency products, services, or practices. Performance 
incentives are included as an allowable expense. 


4-2 


Aligning Utility Incentives with Investment in Energy Efficiency 


Table 4-1. Pros and Cons of Expensing Program Costs 

Pros 


• Expensing treatment is generally consistent with standard utility cost accounting and recovery rules. 

• Avoids the creation of potentially large regulatory assets and associated carrying costs. 

• Provides more-or-less immediate recovery of costs and reduces recovery risk. 

• The use of balancing mechanisms outside of a general rate case ensures more timely recovery when efficiency 
program costs are variable and prevents significant over- or under-recovery from being carried forward to the 
next rate case. 


Cons 


• A combination of infrequent rate cases and escalating expenditures can lead to under-recovery absent a 
balancing mechanism. 

• Can be viewed as single-issue ratemaking. 

• If annual energy efficiency expenditures are large, lump sum recovery can have a measurable short-term 
impact on rates. 

• Some have argued that expensing creates unequal treatment between the supply-side investments (which are 
rate-based) and the efficiency investments that are intended to substitute for new supply. 


• In addition to expending the annual $10 million 
base rate allowance, APS is obligated to spend, on 
average, at least another $6 million annually on ap¬ 
proved eligible DSM-related items. These additional 
amounts are to be recovered by means of a DSM 
adjustment mechanism. 

• All DSM programs must be pre-approved before APS 
may include their costs in any determination of total 
DSM costs incurred. 

• The adjustment mechanism uses an adjustor rate, ini¬ 
tially set at zero, which is to be reset on March 1, 2006, 
and thereafter on March 1 of each subsequent year. 

The adjustor is used only to recover costs in arrears. APS 
is required to file its proposal for spending in excess of 
$10 million prior to the March 1 adjustment. The per- 
kilowatt-hour charge for the year will be calculated by 
dividing the account balance by the number of kilowatt- 
hours used by customers in the previous calendar year. 

• General Service customers that are demand-billed will 
pay a per-kilowatt charge instead of a per-kilowatt- 
hour charge. The account balance allocated to the 
General Service class is divided by the kilowatt billing 


determinant for the demand-billed customers in that 
class to determine the per-kilowatt DSM adjustor 
charge. The DSM adjustor applies to all customers 
taking delivery from the company, including direct 
access customers. 

4.2.5 Case Study: Iowa Energy Efficiency Cost 
Recovery Surcharge 

Until 1997, electric energy efficiency program costs 
were tracked in deferred accounts with recovery in 
a rate case via capitalization and amortization. Since 
then investor-owned utilities in Iowa, pursuant to Iowa 
Code 2001, Section 476.6, 6 recover energy efficiency 
program-related costs through an automatic rate 
pass-through reconciled annually to prevent over- or 
under-recovery (i.e., costs are expensed and recovered 
concurrently). Program costs are allocated within the 
rate classes to which the programs are directed, al¬ 
though certain program costs, such as those associated 
with low income and research and development pro¬ 
grams, are allocated to all customers. The cost recovery 
surcharge is recalculated annually based on historical 
collections and expenses and planned budgets. The 
energy efficiency costs recovered from customers during 


National Action Plan for Energy Efficiency 


4-3 













the previous period are compared to those that were 
allowed to be recovered at the time of the prior adjust¬ 
ment. Any over- or under-collection, any ongoing costs, 
and any change in forecast sales, are used to adjust 
the current energy efficiency cost recovery factors. The 
statute requires that each utility file, by March 1 of each 
year, the energy efficiency costs proposed to be recov¬ 
ered in rates for the 12-month recovery period. This 
period begins at the start of the first utility billing month 
at least 30 days following Iowa Utility Board approval. 

199 Iowa Administrative Code Chapter 35 7 provides 

i 

the detailed cost recovery mechanism in place in Iowa. 
These details are summarized in Appendix D. 

4.2.6 Case Study: Florida Electric-Rider 
Surcharge 

The Florida Energy Efficiency and Conservation Act 
(FEECA) was enacted in 1980 and required the Florida 
Commission to adopt rules requiring electric utilities to 
implement cost-effective conservation and DSM pro¬ 
grams. Florida Administrative Code Rules 25-17.001 
through 25-17.015 require all electric utilities to imple¬ 
ment cost-effective DSM programs. In June 1993, the 
commission revised the existing rules and required the 
establishment of numeric goals for summer and winter 
demand and annual energy sales reductions. 

In order to obtain cost recovery, utilities are required to 
provide a cost-effectiveness analysis of each program 


using the ratepayer impact measure, total resource cost, 
and participant cost tests. 

Investor-owned electric utilities are allowed to recover 
prudent and reasonable commission-approved expenses 
through the Energy Conservation Cost Recovery (ECCR) 
clause. The commission conducts ECCR proceedings 
during November of each year. The commission de¬ 
termines an ECCR factor to be applied to the energy 
portion of each customer's bill during the next calendar 
year. These factors are set based on each utility's esti¬ 
mated conservation costs for the next calendar year, 
along with a true-up for any actual conservation cost 
under- or over-recovery for the previous year (Florida 
PSC, 2007). 

The procedure for conservation cost recovery is 
described by Florida Administrative Code Rule 
25-17.015(1 ); 8 details are included in Appendix D. Table 
4-2 shows the current cost recovery factors. 

Florida Power and Light's (FPL's) recent cost recovery fil¬ 
ing provides some insight into the nature of the adjust¬ 
ment process: 

FPL projects total conservation program costs, net of 
all program revenues, of $ 175,303,326 for the period 
January 2007 through December 2007. The net true-up 
is an over recovery of $4,662,647, which includes the 
final conservation true-up over recovery for January 
2005, through December 2005, of $5,849,271 that 


Table 4-2. Current Cost Recovery Factors in Florida 



Residential Conservation Cost 
Recovery Factor 
(cents per kWh) 

Typical Residential Monthly 

Bill Impact 

(based on 1,000 kWh) 

FPL 

0.169 

$1.69 

FPUC 

0.060 

$0.60 

Gulf 

0.088 

$0.88 

Progress 

0.169 

$1.96 

TECO 

0.073 

$0.73 


Source: Florida PSC, 2007. 


4-4 


Aligning Utility Incentives with Investment in Energy Efficiency 














was reported in FPL's Schedule CT-1, filed May 1, 2006. 
Decreasing the projected costs of $175,303,326 by 
the net true-up over-recovery of $4,662,647 results 
in a total of $170,640,679 of conservation costs (plus 
applicable taxes) to be recovered during the January 
2007, through December 2007, period. Total recover¬ 
able conservation costs and applicable taxes, net of 
program revenues and reflecting any applicable over- or 
under-recoveries are $170,705,441, and the conserva¬ 
tion cost recovery factors for which FPL seeks approval 
are designed to recover this level of costs and taxes. 

4.3 Capitalization and Amortization 
of Energy Efficiency Program Costs 

Capitalization as a cost recovery method is typically re¬ 
served for the costs of physical assets such as generating 
plant and transmission lines. However, some states allow 
the costs of energy efficiency and demand-response 
programs to be treated as capital items, even though the 
utility is not acquiring any physical asset. In the case of 
an investor-owned utility, such capital items are included 
in the utility's rate base. The utility is allowed to earn a 
return on this capital, and the investment is depreciated 
over time, with the depreciation charged as an expense. 
Depending on precisely how a capitalization mechanism 
is structured, it can serve as a strict cost-recovery tool or 
as a utility performance incentive mechanism as well. A 
principle argument made in favor of capitalizing energy 
efficiency program costs is that this treatment places 
demand-and supply-side expenditures on an equal finan¬ 
cial footing. 9 - 10 

Capitalization 11 currently is not a common approach 
to energy efficiency program cost recovery, although 
during the peak of the last major cycle of utility energy 
efficiency investment during the late 1980s and early 
1990s many states allowed or required capitalization. 12 

Capitalization of energy efficiency costs as a cost 
recovery mechanism first appeared in the Pacific North¬ 
west (Reid, 1988). Oregon and Idaho were the first two 


states to allow capitalization of certain selected costs in 
the early 1980s. Washington soon followed with statu¬ 
tory authority for ratebasing that included authorization 
for a higher return on energy efficiency investments. 
Puget Powerl 3 in Washington was allowed to ratebase 
all of its energy efficiency-related costs using a 10-year 
recovery period with no carrying charges applied to the 
costs incurred between rate cases. Montana followed 
Washington in 1983 and adopted a similar mechanism. 
In 1986, Wisconsin switched from expensing the con¬ 
servation expenditures to capitalization and allowed a 
large amount of direct investment to be capitalized with 
a 10-year amortization period. 

With a very few exceptions, capitalization is no longer 
the method of choice for energy efficiency cost re¬ 
covery in these states. The decline in the popularity of 
this approach can be attributed to a variety of factors, 
including the general decline in utility energy efficiency 
investment. However, in several states capitalization was 
abandoned, in part because the total costs associated 
with recovery (given the cost of the return on invest¬ 
ment) were rising rapidly. 

4.3.1 The Mechanics of Capitalization 

As a simplified example, suppose that a utility spends 
$1 million in each of five years for its energy efficiency 
programs, and it is allowed to capitalize and amortize 
these investments over a 10-year recovery period uni¬ 
formly. Table 4-3 illustrates the yearly change in revenue 
requirements, assuming a 10 percent rate of return on 
the unrecovered balance. 

By the end of the 15-year amortization period, the 
total amount collected by the utility through rates is 
$7,250,000. Just as the total cost of purchasing a home 
will be lower with a shorter mortgage, shorter amor¬ 
tization periods yield a lower total cost for recovery of 
the energy efficiency program expenditures. Similarly, 
although the total amount recovered is almost 50 
percent higher in this case than the direct cost of the 
energy efficiency program, the $2,250,000 represents a 
legitimate cost to the utility which comes from the need 


National Action Plan for Energy Efficiency 


4-5 



I 


to carry an unrecovered balance on its books. Concep¬ 
tually, a utility will be indifferent to immediate recovery 
of program costs as an expense and capitalization, as 
the added cost of capitalization should be equal to the 
cost to the utility of effectively lending the $5 million to 
customers. However, in the cases of those states that 
have allowed utilities to earn a return on energy ef¬ 
ficiency investments that exceeds their weighted cost 
of capital, this added return constitutes an incentive for 
investment in energy efficiency that goes beyond that 
provided for traditional capital investments. 

4.3.2 Issues 

The length of time over which an energy efficiency 
investment is amortized (essentially the rate of deprecia¬ 
tion), and the capital recovery rate or rate-of-return on 
the unamortized balance of the investment, both affect 
the total cost to customers of the utility. 


Amortization and Depreciation 

When an expenditure is capitalized, the recovery of 
this expenditure is spread over several years, with 
predetermined amounts recovered in rates each 
year during the recovery or amortization period. 

The depreciation or amortization rate is the fraction 
of unrecovered cost that is recovered each year. Tax 
law and regulation generally govern the specific rate 
used for different types of capital investments such as 
generating or distribution plant and equipment and 
other physical structures. However, since the costs of 
energy efficiency programs typically are not considered 
capital items, there is no universally accepted deprecia¬ 
tion rate applied to energy efficiency program costs that 
are capitalized. An early study (Reid, 1988) of energy 
efficiency capitalization found that amortization pro¬ 
grams for conservation expenditures ranged from three 
to 10 years. For example, Washington and Wisconsin 
allowed a 10-year recovery period for amortization. 


Table 4-3. Illustration of Energy Efficiency Investment Capitalization 


End-of- 

year 

Annual 

Energy- 

Efficiency 

Expenditure 

Cumulative 

Energy- 

Efficiency 

Expenditure 


Unamortized 

Balance 

Return on 

Un recovered 
Investment 

Incremental 

Revenue 

Requirements 

1 

1 , 000,000 

1 , 000,000 

$ 100,000 

$ 900,000 

$ 90,000 

$ 190,000 

2 

1 , 000,000 

2 , 000,000 

$ 200,000 

$ 1 , 700,000 

$ 170,000 

$ 370,000 

3 

1 , 000,000 

3 , 000,000 

$ 300,000 

$ 2 , 400,000 

$ 240,000 

$ 540,000 

4 

1 , 000,000 

\ 

4 , 000,000 

$ 400,000 

$ 3 , 000,000 

$ 300,000 

$ 700,000 

5 

1 , 000,000 

5 , 000,000 

$ 500,000 

$ 3 , 500,000 

$ 350,000 

$ 850,000 

6 


■ 

$ 500,000 

$ 3 , 000,000 

$ 300,000 

$ 800,000 

7 



$ 500,000 

$ 2 , 500,000 

$ 250,000 

$ 750,000 

8 


' 

$ 500,000 

$ 2 , 000,000 

$ 200,000 

$ 700,000 

9 



$ 500,000 

$ 1 , 500,000 

$ 150,000 

$ 650,000 

10 



$ 500,000 

$ 1 , 000,000 

$ 100,000 

$ 600,000 

11 



$ 400,000 

$ 600,000 

$ 60,000 

$ 460,000 

12 



$ 300,000 

$ 300,000 

$ 30,000 

$ 330,000 

13 



$ 200,000 

$ 100,000 

$ 10,000 

$ 210,000 

14 



$ 100,000 

$0 

$0 

$ 100,000 

15 /Total 

5 , 000,000 


$ 5 , 000,000 


$ 2 , 250,000 

$ 7 , 250,000 


4-6 


Aligning Utility Incentives with Investment in Energy Efficiency 

































Massachusetts used the lifetime of the energy efficien¬ 
cy equipment for the recovery period. 

Rate of Return ^ 4 

Just as the interest rate on a home mortgage can 
greatly affect both the monthly payment and the total 
cost of the home, the rate of return allowed on the 
unamortized cost of an energy efficiency program can 
significantly affect the cost of that program to ratepay¬ 
ers. Rates-of-return for investor-owned utilities are set 
by state regulators based on the relative costs of debt 
and equity. In the case of publicly and cooperatively 
owned utilities, the return much more closely mirrors 
the cost of debt. The ROE, in turn, is based on an as¬ 
sessment of the financial returns that investors in that 
utility would expect to receive—an expectation that is 
influenced by the perceived riskiness of the investment. 
This riskiness is related directly to the perceived likeli¬ 
hood that a utility will, for some reason, not be able to 
earn enough money to pay off the investment. 

Unless the level of energy efficiency program invest¬ 
ment is significant relative to a utility's total unamor¬ 
tized capital investment, the relative riskiness of energy 
efficiency versus supply-side investments is not a major 
issue. However, if this investment is significant, the rela¬ 
tive risk of an energy efficiency investment can become 
an issue for a variety of reasons, including: 

• These resources are not backed by physical assets. 
While a utility actually owns gas distribution mains 
or generating plants, it does not own an efficient air 
conditioner that a customer installs through a utility 
program. If energy efficiency spending is accrued for 
future recovery, either by expensing or amortization, 
this accrual is considered as a "regulatory asset"—an 
asset created by regulatory policy that is not backed 
by an actual plant or equipment. Carrying substantial 
regulatory assets on the balance sheet can hurt a 
utility's financial rating. 

• The investment becomes more susceptible to disal¬ 
lowance. Recovery of a capital investment typically is 
allowed only for investments deemed prudent and 
used-and-useful. Because energy efficiency programs 
are based on customer behavior, and because that 


behavior is difficult to predict, it is possible that 
the investment being recovered does not actually 
produce its intended benefit. This result could lead 
regulators to conclude that the investment was not 
prudent or used-and-useful. This risk owes more to 
the fact that energy efficiency program effectiveness 
is subject to ex post evaluation. As program design 
and implementation experience grows, program real¬ 
ization rates (the ratio of actual to expected savings) 
increases, and this risk diminishes. It is not clear that 
this risk is any different with respect to its ultimate 
effect than the risks associated with the construction 
and operation of a utility plant. 

• Potential uncertainty arising from policy changes 
that govern energy efficiency incentive mechanisms 
heightens the risk. Although both supply- and 
demand-side resources are subject to policy risk, the 
modularity and short lead-times associated with de¬ 
mand-side resources (which is a distinct benefit from 
a resource planning perspective) also create more 
opportunities to revisit the policies governing energy 
efficiency expenditure and cost recovery. The fact 
that energy efficiency program costs are regulatory 
assets in theory, means that the regulatory policy 
underlying those assets can change with changes in 
the regulatory environment. The pressure to modify 
policies governing recovery of program costs has 
increased historically as the size of these assets has 
grown with increases in program funding. 

4.3.3 Pros and Cons 

Based on experience to date, capitalization and amorti¬ 
zation carries pros and cons as illustrated in Table 4-4. 

4.3.4 Case Study: Nevada Electric 
Capitalization with ROE Bonus 

Nevada is the only state currently that allows recovery of 
energy efficiency program costs using capitalization as 
well as a bonus return on those costs. Development and 
administration of energy efficiency programs by Nevada's 
regulated electric utilities takes place within the context 
of an integrated resource planning process combined 
with a resource portfolio standard that allows energy ef¬ 
ficiency programs to fulfill up to 25 percent of the utilities' 


National Action Plan for Energy Efficiency 


4-7 



H 


portfolio requirements. Over the past several years spend¬ 
ing on energy efficiency programs has risen substantially, 
both as a response to rapid growth in electricity demand 
and as Nevada Power and Sierra Pacific Power have at¬ 
tempted to maximize the contribution of energy efficiency 
to portfolio requirements as those requirements grow. 

All prudently incurred costs associated with energy effi¬ 
ciency programs are recoverable pursuant to the Nevada 
Administrative Code 704.9523. A utility may seek to 
recover any costs associated with approved programs 
for conservation and DSM, including labor, overhead, 
materials, incentives paid to customer, advertising, and 
program monitoring and evaluation. 

Mechanically, the Nevada mechanism works as follows 
for those approved programs not already included in a 
utility's rate base: 

• The utility tracks all program costs monthly in a sepa¬ 
rate account. 

• A carrying cost equal to 1/12 of the utility's annual 
allowed rate of return is applied to the balance in the 
account. 


• At the time of the next rate case, the balance in the 
account (including program costs and carrying costs) 
is cleared from the tracking account and moved into 
the utility's rate base. 

• The commission sets an appropriate amortization 
period for the account balance based on its determi¬ 
nation of the life of the investment. 

• The utility applies a rate of return to the unamortized 
balances equal to the authorized rate of return plus 5 
percent (for example a 10.0 percent return becomes 
10.5 percent). 

Nevada's current cost recovery/incentive structure has 
been in place since 2001. However, with the recent 
rapid rise in utility energy efficiency program spending, 
concerns also have arisen with respect to the structure 
of the mechanism and its effect on the utilities' invest¬ 
ment incentives. These concerns prompted the Nevada 
Public Service Commission to open an investigatory 
docket in late 2006. In its Revised Order in Docket Nos. 
06-0651 and 07-07010 on January 30, 2007, the com¬ 
mission wrote that: 


Table 4-4. Pros and Cons of Capitalization and Amortization 

Pros 


• Places energy efficiency investments on more of an equal footing with supply-side investment with respect to 
cost recovery 

• Capitalization can help make up for the decline in utility generation and transmission and distribution assets 
expected to occur, as energy efficiency defers the need for new supply-side investment. 

• As part of this equalization, enables the utility to earn a financial return on efficiency investments. 

• Smoothes the rate impacts of large swings in annual energy efficiency spending. 


Cons 


• Treats what is arguably an expense as a capital item. 

• Creates a regulatory asset that can grow substantially over time; because this asset is not tangible or owned 
by utility, it tends to be viewed as more risky by the financial community. 

• Delays full recovery and boosts recovery risk. 

• To the extent that the return on the energy efficiency program investment is intended to provide a financial 
incentive for the utility, this incentive is not tied to program performance. 

• Raises the total dollar cost of the efficiency programs. 


4-8 


Aligning Utility Incentives with Investment in Energy Efficiency 











[We] believe that appropriate incentives for utility DSM 
programs are necessary. The exact nature and form of 
incentives that should be offered for such programs in¬ 
volve a number of factors, including the regulatory and 
statutory environment. The current incentives for DSM 
were implemented in 2001 when the companies had 
few, if any, incentives to implement DSM programs. The 
enactment of A.B. 3 changed both the regulatory and 
statutory context. Utilities now have incentives to imple¬ 
ment DSM to meet portions of their respective renew¬ 
able portfolio standard requirements. Nevada Power 
Company's expenditures will increase almost four times 
compared to pre A.B. 3 during this action plan. Given 
these changes, it is now time to reexamine the manda¬ 
tory package of incentives provided to DSM programs. 

This includes the types and categories of costs eligible 
for expense treatment, as well as prescribed incentives. 

The commission therefore directs its secretary to open 
an investigation and rulemaking into the appropriate¬ 
ness of DSM cost recovery mechanisms and incentives. 

In early 2007, the commission asked all interested par¬ 
ties to comment on four specific issues, as identified 
below: 

• What are the public policy objectives of an incentive 
structure? i.e., Should only the most cost-effective 
programs be incented? Should only the most 
strategic programs be incented? 

• Does the current incentive structure provide the 
appropriate incentives to fulfill each public policy 
objective? 

I 

• Are there alternative incentive structures that the 
commission should consider? If so, what are these 
incentives and how would each further the goals 
identified above? 

• How should the current incentive structure be rede¬ 
signed? i.e., what expenses should be included in the 
incentive mechanism? What should be the basis for 
determining incentives? 

Commission staff have argued that the underlying 
rationale for utility energy efficiency investments is 


found in the integrated resource planning process. Staff 
noted that utilities should be inclined to pursue those 
programs that contribute to the least-cost resource mix. 
The addition of the resource portfolio requirement and 
the ability to meet up to 25 percent of that requirement 
provides further incentive to pursue energy efficiency 
investment. At the same time, staff argued that the cur¬ 
rent cost recovery mechanism, with the addition of the 
five percentage point rate of return bonus, provided no 
incentive for effective program performance and in fact, 
simply encouraged additional spending with no consid¬ 
eration for the implementation outcome—an argument 
echoed by the Attorney General's Bureau of Consumer 
Protection. Staff recommended that the ideal solution is 
to tie incentives to program performance and to share 
program net benefits with ratepayers. 

Nevada Power Company and Sierra Pacific Power Com¬ 
pany have endorsed the existing mechanism as provid¬ 
ing appropriate incentives to fulfill the public policy 
objective of achieving a net benefit for customers while 
providing a stable and motivating incentive for the 
utility. According to the companies, the current incen¬ 
tive scheme with the bonus rate of return recognizes 
the increased risks associated with DSM investments 
compared to the supply-side investments, and they 
argue that changing the existing incentive structure will 
create uncertainty and therefore, increase the perceived 
risk associated with energy efficiency investments. They 
further argue that the integrated resource plan review 
process ensures that program budgets are given de¬ 
tailed review. 

4.4 Notes 

1. Depreciation of capital equipment is, however, treated as an 
expense. 

2. An "opt-out" allows a customer, typically a large customer, to 
elect to not participate in a utility program and to avoid paying 
associated program costs. Some states do not allow opt-outs, but 
will allow large customers to spend the monies that otherwise 
would be collected from them by utilities for efficiency projects in 
their own facilities. This often is called "self-direction." 

3. Wisconsin investor-owned utilities use "escrow accounting" 
as a form of a balancing account. Should the Public Service 


National Action Plan for Energy Efficiency 


4-9 


Commission authorize a utility to incur specific program costs 
during a period between rate cases, these costs are recorded in an 
escrow account. Carrying charges are applied to the balance. The 
balance of the escrow account is cleared into the revenue require¬ 
ment at the time of the next rate case (typically every two years). 

4. As discussed elsewhere in this paper, addressing recovery of pro¬ 
gram costs as a separate matter apart from all other utility cost 
changes could be considered single-issue ratemaking which can 
be prohibited. 

5. Order No. 67744, In the Matter of the Application of the Arizona 
Public Service Company for a Hearing to Determine the Fair 
Value of the Utility Property of the Company for Ratemaking 
Purposes, to Fix a Just and Reasonable Rate of Return Thereon, 
to Approve Rate Schedules Designed to Develop such Return, 
and for Approval of Purchased Power Contract, Docket No. E- 

01345-A-03-0437, accessed at <www.azcc.gov/divisions/utilities/ 
electric/APS-FinalOrder.pdf>. 

6. Iowa Code 2001: Section 476.6, accessed at <www.legis.state, 
ia. us/I AC ODE/2001/476/6.html>. 

7. 199 Iowa Administrative Code Chapter 35, accessed at <www. 
legis.state.ia.us/Rules/Current/iac/199iac/19935/19935.pdf>. 

8. Florida Administrative Code Rule 25-17.015(1), accessed at 
<www.flrules.org/gateway/RuleNo.asp?ID=25-17.015>. 

9. Some have argued that capitalization and amortization of energy 
efficiency program costs provides an incentive to utilities to invest 
in energy efficiency without regard to the performance of the 
programs. See the Nevada case study below for a broader treat¬ 
ment of this issue. 


10. From a narrow theoretical perspective, there should be no signifi¬ 
cant financial difference between expensing and capitalization. The 
return on capital is intended to compensate a utility for the cost 

of money used to fund an activity. For investor-owned utilities, this 
compensation includes payment to equity investors. Flowever, if 
program expenses are immediately expensed—that is, if the utility 
can immediately recover each dollar it expends on a program—the 
utility does not need to "advance" capital to fund the programs, 
and therefore, there is no cost incurred by the utility. 

11. This Report uses the generic term "capitalization" as opposed to 
"ratebasing," since, in some states, energy efficiency program 
costs technically are not included in a utility's rate base but are 
treated in a similar fashion via capitalization. 

12. The following states either have used in the past or continue 
to use some form of capitalization of energy efficiency costs: 
Oregon, Idaho, Washington, Montana, Texas, Wisconsin, Nevada, 
Oklahoma, Connecticut, Maine, Massachusetts, Vermont, and 
Iowa. With the exception of Nevada, most of these states are 

no longer using capitalization, though it remains an option. See 
Reid, M. (1988). Ratebasing of Utility Conservation and Load 
Management Programs. The Alliance to Save Energy 

13. Puget Power is now known as Puget Sound Energy. 

14. "Rate of return" is used in this context to refer to the rate ap¬ 
plied to an unamortized balance that is used to represent the cost 
of money to the utility. In the case of investor-owned utilities, this 
rate is usually a weighted average of the interest rate on debt 
and the allowed return on equity. 


4-10 


Aligning Utility Incentives with Investment in Energy Efficiency 



Lost Margin Recovery 




This chapter provides a practical overview of alternative mechanisms to address the recovery of lost mar¬ 
gins and presents their pros and cons. Detailed case studies are provided for each mechanism. 


5.1 Overview 

Chapter 2 of the Action Plan provides a concise ex¬ 
planation of the throughput incentive and a summary 
of options to mitigate the incentive. This incentive 
has been identified by many as the primary barrier 
to aggressive utility investment in energy efficiency. 
Policy expectations that utilities aggressively pursue the 
implementation of energy efficiency programs create a 
conflict of interest for utilities in that they cannot fulfill 
their obligations to their shareholders while simultane¬ 
ously encouraging energy efficiency efforts of their 
customers, which will reduce their sales and margins in 
the presence of the throughput incentive. 

Any approach aiming to eliminate, or at least neutral¬ 
ize, the impact of the throughput incentive on effective 
implementation of energy efficiency programs must ad¬ 
dress the issue of lost margins due to successful energy 
efficiency programs. Two major cost recovery approaches 
have been tried since the 1980s with this objective in 
mind; decoupling and lost revenue recovery. 1 A third 
approach, known generically as straight fixed-variable 
(SFV) ratemaking, conceptually provides a solution to the 
problem by allocating most or all fixed costs to a fixed 
(non-volumetric) charge. Under such a rate design, re¬ 
ductions in the volume of sales do not affect recovery of 
fixed costs. While conceptually appealing, this approach 
carries with it complex implementation issues associ¬ 
ated with the transition from a structure that recovers 
fixed costs via volumetric charges to a SFV structure. It 
also can reduce the financial incentive for end-users to 
pursue energy efficiency investments by reducing the 
value that consumers realize by reducing the volume of 
consumption—an issue more likely to impact electricity 
^consumers than gas customers, since commodity cost 


represents a larger share of a consumer's total gas bill. 
While it has seen application in the natural gas industry, 
SFV ratemaking is uncommon in the electric industry 
(see American Gas Association, 2007). 

5.2 Decoupling 

The term "decoupling" is used generically to represent 
a variety of methods for severing the link between 
revenue recovery and sales. These methods vary widely 
in scope, and it is rare that a mechanism fully decouples 
sales and revenues. Some approaches provide for limit¬ 
ed true-ups in attempts to ensure that utilities continue 
to bear the risks for sales changes unrelated to energy 
efficiency programs. Some focus on preserving recovery 
of lost margins. This focus recognizes that a sales reduc¬ 
tion will be accompanied by some cost reduction, and 
therefore, the total revenue requirement will be lower. 
Truing up total revenue would, in such cases, boost 
utility earnings. 

In recent years, decoupling has re-emerged as an ap¬ 
proach to address the margin recovery issue facing utili¬ 
ties implementing substantial energy efficiency program 
investments. Decoupling can be defined generally as a 
separation of revenues and profits from the volume of 
energy sold and, in theory, makes a utility indifferent 
to sales fluctuations. Mechanically, decoupling trues-up 
revenues via a price adjustment when actual sales are 
different than the projected or test year levels. 

Decoupling mechanisms appear under various names 
including the following listed by the National Regulatory 
Research Institute (Costello, 2006): Conservation Margin 
Tracker; Conservation-Enabling Tariff; Conservation Tariff; 
Conservation Rider; Conservation and Usage Adjustment 


National Action Plan for Energy Efficiency 


5-1 


T 


(CUA) Tariff; Conservation Tracker Allowance; Incentive 
Equalizer; Delivery Margin Normalization; Usage per 
Customer Tracker; Fixed Cost Recovery Mechanism; and 
Customer Utilization Tracker. Although often cited as a 
solution to the throughput issue raised by energy ef¬ 
ficiency programs, decoupling is also a mechanism that 
often is generally suggested as a way to smooth earnings 
in the face of sales volatility. Natural gas utilities have 
been among the strongest advocates of decoupling be¬ 
cause of its ability to moderate the impacts of abnormal 
weather and declining usage per customer, in addition 
to its ability to mitigate the under-recovery of fixed costs 
caused by energy efficiency programs (see American Gas 
Association, 2006a). 

A decoupling mechanism will sometimes include a balanc¬ 
ing account in order to ensure the exact collection of the 
revenue requirement, although this approach typically 
is used only if there is an extended period between rate 
adjustments. If revenues collected deviate from allowed 
revenues, the difference is collected from or returned to 
customers through periodic adjustments or reconciliation 
mechanisms. If a successful energy efficiency program 
reduces sales, there will not be any loss in revenue result¬ 
ing from these energy efficiency programs. If sales turn 


out to be higher than the projected, the excess revenue is 
returned to the ratepayer. 

There are two major forms of revenue decoupling— 
those linked to total revenue and those focused on 
revenue per customer: the revenue a utility is allowed 
to earn is capped in the former, and the revenue per 
customer is capped in the latter. The primary advantage 
of a revenue-per-customer model is that it recognizes 
the link between a utility's revenue requirement and 
its number of customers. For example, if a decoupling 
mechanism caps total revenue, and if the utility experi¬ 
ences a net increase in customers, all else being equal, 
the allowed level of revenue will fall short of the cost of 
serving the additional customers, leading to a drop in 
earnings. A revenue-per-customer mechanism allows to¬ 
tal revenue to grow (or fall) as the number of customers 
and associated costs rise (fall). 

Table 5-1 shows a simple example (constructed similarly to 
the example in Eto et al., 1994) illustrating the basic decou¬ 
pling mechanism with a balancing account. 

For year 1, the revenue requirement of $100 is autho¬ 
rized through the general rate case. Given projected 
sales of 1,000 therms, the price is determined to be 10 


Table 5-1. Illustration of Revenue Decoupling 



Rate 

1 

$100.00 

1,000 

Case 1 

2 

$100.00 

1,000 

Rate 

Case 2 

3 

$111.10 

1,010 


DC 


0.100 

$100.00 

0.100 

1,100 

$110.00 

$10.00 

-$10.00 

0.100 

$90.00 

0.090 

990 

$89.10 

-$10.90 

$0.90 

0.110 

$112.00 

0.111 

1,010 

$112.00 

$0.90 

$0.00 


5-2 


Aligning Utility Incentives with Investment in Energy Efficiency 




































cents/therm. If actual sales are 1,100 therms, then at 
the rate of 0.1 $/therm, the actual realized revenue is 
$110. The utility places the $ 10 difference between the 
actual revenue and the allowed revenue in a balanc¬ 
ing account. The next year, the utility needs to collect 
only $90 to reach the $100 authorized revenue and the 
price per therm is set at 9 cents. If the sales were indeed 
1,000 therms, the utility would make $90, and with the 
$10 in the balancing account, it would exactly meet the 
authorized revenue’ However, in this example, the sales 
are 990 therms, and utility revenue is $89.10 at 9 cents/ 
therm. The utility needs to collect 90 cents from the 
ratepayers. 

Suppose that the revenue requirement is reset to 
$ 111.10 at the projected sales level of 1,010 therms. 
The utility needs to collect the balance in the balanc¬ 
ing account and its authorized revenue of $111.10, 
a total of $ 112. At the projected sales level of 1,010, 
the price needs to be set at 11.1 cents per therm to 
recover $112. Suppose that the utility's sales are actually 
equal to the projected sales of 1,010. The utility recov¬ 
ers exactly $112 and there is a zero balance left in the 
balancing account. 

Under the revenue-per-customer cap approach, the 
actual revenues collected per customer are compared 
to the authorized revenues per customer, and the 


balancing account maintains the over- or under-earn¬ 
ings. A simple example of the revenue cap-per-customer 
approach is illustrated in Table 5-2. 

In this example, the revenue per customer to be collect¬ 
ed is fixed or capped. Assuming monthly adjustments, 
actual revenues collected per customer are compared 


Performance-Based Ratemaking and 
Decoupling 


Performance-Based Ratemaking (PBR) is an alterna¬ 
tive to traditional return on rate base regulation 
that attempts to forego frequent rate cases by 
allowing rates or revenues to fluctuate as a func¬ 
tion of specified utility performance against a set of 
benchmarks. One form of PBR embodies a revenue 
cap mechanism that functions very much like a 
decoupling, wherein price is allowed to fluctuate as 
a way to true-up actual revenues to allowed reve¬ 
nues. The revenue-cap PBR mechanism can be more 
complex, incorporating a variety of specific adjust¬ 
ments to both price and revenue. In most cases, if 
a utility operates under revenue-cap PBR, sales and 
revenues are decoupled for purposes of energy ef¬ 
ficiency investment, although specific adjustments 
may be required to allow prices to be adjusted for 
changes in actual program costs as well as changes 
in margins. 


Table 5-2. Illustration of Revenue per Customer Decoupling 

A 


Revenue requirements ($) 

100 

B 


Expected sales (therms) 

1,000 

C 

(A-rB) 

Price set in the rate case ($/therm) 

0.1 

D 


Number of customers 

100 

E 

(Ah-D) 

Allowed revenue per customer ($/therm) 

1 

F 


Actual sales (therms) 

950 

G 

(CxF) 

Actual revenue ($) 

95 

H 


Actual number of customers 

101 

1 


Allowed revenue ($) 

101 

J 

(l-G) 

Revenue adjustment ($) 

6 


National Action Plan for Energy Efficiency 


5-3 



















to the allowed revenue per customer for that month. 
The difference is recorded in a balancing account and 
reconciled periodically. In this case, because of customer 
growth, the utility is allowed to collect $6 more than 
the initial revenue requirement. 

Revenue decoupling has been a part of gas ratemaking 
for over two decades, with revenue cap-per-customer 
the more commonly encountered approach. 2 Interest 
has increased over the past several years due to in¬ 
creased customer conservation in response to high gas 
prices and utility-funded energy efficiency initiatives. In 
addition, natural gas usage per household has declined 
more than 20 percent since the 1980s and is projected 
to continue to decline in the future in many jurisdictions 
(Costello, 2006). In such cases, decoupling provides an 
automatic adjustment mechanism that allows the utility 
to be revenue neutral and can help defer otherwise 
needed rate cases. 

Early experience with decoupling, as recounted in Chap¬ 
ter 2 of the Action Plan, provides important lessons. 3 
In 1991, the Maine PUC adopted a revenue decoupling 
mechanism in the form of revenue-per-customer cap for 
Central Maine Power (CMP) on a three-year trial basis. 
The utility's allowed revenue was determined through 
a rate case and adjusted annually in accordance with 
changes in the number of customers. CMP was allowed 
to file a rate case at any time to adjust its authorized 
revenues. With the economic downturn Maine expe¬ 
rienced around the time the mechanism was in place, 
sales dipped significantly leading to a large unrecovered 
balance ($52 million by the end of 1992) that needed 
to be charged to the ratepayers. In fact, the portion 
of the energy efficiency-related drop in the sales was 
very small. Nevertheless, the program in its entirety was 
terminated in 1993. 

Currently, a number of jurisdictions are investigating the 
advantages and disadvantages of decoupling, including 
Arizona, Colorado, Delaware, the District of Colum¬ 
bia, Delaware, Hawaii, Kentucky, Maryland, Michigan, 
New Hampshire, New Mexico, Pennsylvania, Tennessee, 
and Virginia. Sixteen states have adopted either gas 
or electric decoupling programs for at least one utility. 


Arkansas, New York, Utah, Oregon, Washington, Idaho, 
and Minnesota are among the states recently adopting 
decoupling programs. 4 

Table 5-3 suggests the possible pros and cons of decou¬ 
pling. The specific nature of the decoupling mechanism 
and, in particular, the nature of adjustments for factors 
such as weather and economic growth, will determine 
the extent to which the link between sales and profits is 
affected. 

5.2.1 Case Study: Idaho's Fixed Cost Recovery 
Pilot Program 

The mechanism adopted in Idaho to address the im¬ 
pacts of efficiency program-induced changes in sales 
should not be viewed as decoupling in the broadest 
sense of that term. While it contains a number of the el¬ 
ements found in decoupling plans, it is focused specifi¬ 
cally on recovery of lost fixed-cost revenues. The Idaho 
Public Utilities Commission initiated Case No. IPC-04-15 
in August 2004, to investigate financial disincentives to 
investment in energy efficiency by Idaho Power Compa¬ 
ny. A series of workshops was conducted, and a written 
report was filed with the commission in early 2005. The 
report pointed to two action items: 

1. The development of a true-up simulation to track 
what might have occurred if a decoupling or true-up 
mechanism had been implemented for Idaho Power 
at the time of the last general rate case. 

2. The filing of a pilot energy efficiency program that 
would incorporate both performance incentives and 
fixed-cost recovery. 

During the investigation, the parties agreed that there 
were disincentives preventing higher energy efficiency 
investment by Idaho Power, but no agreement was 
reached on whether or not the return of lost fixed-cost 
revenues would result in removing the disincentives. The 
parties agreed to conduct a simulation of the proposed 
mechanism, the results of which indicated that lost 
fixed-cost revenues, in fact, produced barriers to energy 
efficiency investments and, therefore, a three-year pilot 
mechanism to allow recovery of fixed-cost revenue 
losses should be approved. 


5-4 


Aligning Utility Incentives with Investment in Energy Efficiency 


Table 5-3. Pros and Cons of Revenue Decoupling 

Pros 


• Revenue decoupling weakens the link between sales and margin recovery of a utility, reducing utility re¬ 
luctance to promote energy efficiency, including building codes, appliance standards, and other efficiency 
policies. 

• Through decoupling, the utility's revenues are stabilized and shielded from fluctuations in sales. Some have 
argued that this, in turn, might lower its cost of capital. 5 (For a discussion of this issue, see Hansen, 2007, 
and Delaware PSC, 2007). The degree of stabilization is a function of adjustments made for weather, eco¬ 
nomic growth, and other factors (some mechanisms do not adjust revenues for weather or economic growth- 
induced changes in sales). 6 

• Decoupling does not require an energy efficiency program measurement and evaluation process to determine 
the level of under-recovery of fixed costs. 7 

• Decoupling has a low administrative cost relative to specific lost revenue recovery mechanisms. 

• Decoupling reduces the need for frequent rate cases and corresponding regulatory costs. 


Cons 


• Rates (and in the case of gas utilities, non-gas customer rates) can be more volatile between rate cases, 
although annual caps can be instituted. 

• Where carrying charges are applied to balancing accounts, the accruals can grow quickly. 

• The need for frequent balancing or true-up requires regulatory resources; may be a lesser commitment than 
required for frequent rate cases. 


Idaho Power filed an application with the Idaho Public 
Utilities Commission in January of 2006, and requested 
authority to implement a fixed cost adjustment (FCA) 
decoupling or true-up mechanism for its residential and 
small General Service customers. The commission staff, 
the NW Energy Coalition, and Idaho Power negoti¬ 
ated a settlement agreement, and the commission 
approved a Joint Motion for Approval of Stipulation in 
December 2006. 

The commission issued Order No. 30267 (Idaho PUC, 
2007) approving the FCA as a three-year pilot program, 
noting that either staff or Idaho Power can request 
discontinuance of the pilot. Program implementation 
began on January 1, 2007, and will last through De¬ 
cember 31, 2009, plus any carryover. The first rate ad¬ 
justment will occur June 1, 2008, and subsequent rate 
adjustments will occur on June 1 of each year during 
the term of the pilot. 


The proposed FCA is applicable to residential service 
and small General Service customers because, as the 
company noted, these two classes present the most 
fixed-cost exposure for the company. The FCA is de¬ 
signed to provide symmetric rate adjustment (up or 
down) when fixed-cost recovery per customer varies 
above or below a commission-established level. While 
this approach fits the conventional description of a 
decoupling mechanism, Idaho Power noted that a more 
accurate description of the mechanism is a "true-up." 
The fixed-cost portion of the revenue requirement 
would be established for residential and small General 
Service customers at the time of a general rate case. 
Thereafter, the FCA would provide the mechanism to 
true-up the collection of fixed costs per customer to 
recover the difference between the fixed costs actually 
recovered through rates and the fixed costs authorized 
for recovery in the company's most recent general rate 
case. The FCA mechanism incorporates a 3 percent 


National Action Plan for Energy Efficiency 


5-5 








cap on annual increases, with carryover of unrecovered 
deferred costs to subsequent years. 

The actual number of customers in the adjustment year 
for each customer class to which the mechanism applies 
is multiplied by the assumed fixed cost per customer, 
which is determined by dividing the total fixed costs by 
the total number of customers from the last general rate 
case. This allowed fixed-cost recovery amount is com¬ 
pared with the amount of fixed costs actually recovered 
by the Idaho Power. The actual fixed-cost recovery is 
determined by multiplying the weather-normalized sales 
for each class by the fixed-cost per kilowatt-hour rate 
also determined in the general rate case. The difference 
between the allowed and the actual fixed-cost recovered 
amounts is the fixed-cost adjustment for each class. 

For customer billing purposes only, the commission-ap¬ 
proved FCA adjustment is combined with the conserva¬ 
tion program funding charge. 

While recognizing the potential value of the true-up 
mechanism, parties have taken a cautious approach that 
allows the company and the commission to gain experi¬ 
ence in implementing, monitoring, and evaluating the 
program. And, since the program is a pilot, program 
corrections or cessation will take place if it is found 
unsuccessful or if unintended consequences develop. 
From the commission's perspective, the company must 
demonstrate an "enhanced commitment" to energy ef¬ 
ficiency investment resulting from implementation of the 
FCA, including making efficiency and load management 
programs widely available, supporting building code 
improvement activity, pursuing appliance standards, and 
expanding of DSM programs. 

Despite the approval of the pilot, the commission staff 
raised a number of the technical issues related to the 
relationship between energy efficiency program imple¬ 
mentation and the application of the true-up mechanism. 
Given that the success of the mechanism is being deter¬ 
mined in part by how it affects the company's investment 
in energy efficiency, several issues were raised regard¬ 
ing how that commitment was to be measured and, 
specifically, how evidence of that commitment could be 
distinguished from factors affecting sales per customer 


unrelated to the company's energy efficiency efforts. The 
commission noted that FCA will require close monitoring, 
and the development of proper metrics to evaluate the 
company's performance remains an issue. 

5.2.2 Case Study: New Jersey Gas Decoupling 

A relatively novel decoupling mechanism has recently 
been approved in New Jersey. In late 2005, New Jersey 
Natural Gas (NJNG) and South Jersey Gas (SJG) jointly 
filed proposals with the New Jersey Board of Public Utili¬ 
ties to implement a CUA clause in a five-year pilot pro¬ 
gram. The CUA was proposed as a way to "[sjeparate 
the companies' margin recoveries from throughput and 
to adjust margin recoveries for variances in customer 
usage, enabling the companies to aggressively promote 
conservation and energy efficiency by their customers" 
(New Jersey BPU, 2006). 

The companies, the New Jersey Utility Board Staff, and 
the Department of the Public Advocate reached a settle¬ 
ment agreement that was approved by the New Jersey 
Commission in October 2006. Through the settlement, 
the proposed CUA was modified and implemented on a 
three-year pilot basis and renamed as the Conservation 
Incentive Program (CIP). The CIP replaced the Weather 
Normalization Clause, which helped cover weather- 
related fluctuations. The CIP is an incentive-based 
program that: 

• Requires the companies to implement shareholder- 
funded conservation programs designed to aid 
customers in reducing their costs of natural gas and 
to reduce each utility's peak winter and design day 
system demand. 

• Requires the companies to reduce gas supply related 
costs. 

• Allows the companies to recover from customers 
certain non-weather margin revenue losses limited to 
the level of gas supply cost savings achieved. 

The companies are required to make annual CIP filings, 
based on seven months of actual data and five months 
of projected data, with a June 1 filing date. The filings 
are to document actual results, perform the required 


5-6 


Aligning Utility Incentives with Investment in Energy Efficiency 


CIP collection test, and propose the new CIP rate. Any 
variances from the annual filings will be trued up in the 
subsequent year. The board has reserved the right to re¬ 
view any aspect of the companies' programs, including, 
but not limited to, the sufficiency of program funding. 

The CIP tariffs include ROE limitations on recoveries 
from customers for both the weather and non-weather- 
related components. In the case of South Jersey Gas, 
the ROE was set at the level of the company's most 
recent general rate case. The ROE for New Jersey Natu¬ 
ral Gas was set at 10.5 percent (compared to its most 
recently authorized rate of 11.5 percent). 

The most significant element of the CIP tariff is its 
requirement that, as a condition for decoupling, the 
utilities must reduce gas supply costs—the so-called Basic 
Gas Supply Service (BGSS) savings—such that consumers 
see no net change in costs. 

The methodology employed to calculate the non¬ 
weather-related CIP surcharge, if any, is delineated in 
paragraph 33(a) of the stipulation. If the non-weather- 
related CIP recovery is less than or equal to the level of 
available gas cost savings, the amount will be eligible 
for recovery through the CIP tariffs. Any portion of the 
non-weather CIP value that exceeds the available gas 
cost savings will not be recovered in the current period, 
will be deferred up to three years, and will be subject 
to an eligibility test in the subsequent period. Deferred 
CIP surcharges may be recovered in a future period to 
the extent that available gas cost savings are available 
to offset the deferred amount. If the pilot is terminated 
after the initial period, any remaining deferred CIP 
surcharges will not be recovered. The value of any BGSS 
savings during one year in excess of the non-weather 
CIP value cannot be carried forward for use in future 
year calculations. 

NJNG will provide $2 million for program costs and 
SJG will provide $400,000 for each year of the pilot 
program, all of which will come from shareholders. 

The companies are required to provide the full cost 
of the programs, even if the program costs exceed 
the budgeted levels. 


In approving the stipulation, the commission concluded 
with the following: 

With the CIP and the possible recovery of non-weather- 
related margin losses, the utilities have represented 
that they will actively promote conservation and energy 
efficiency by their customers through programs funded 
by their shareholders. The programs are not to replicate 
existing CEP programs and are to include, among other 
things, customized customer communications and 
outreach built upon the utilities' relationships with their 
customers. While not replicating existing CEP programs, 
the CIP programs include initiatives that promote 
customers' use of CEP programs through consistent 
messaging with the CEP programs. At the same time, 
by limiting non-weather-related CIP recovery by gas 
supply cost reductions, in addition to an earnings cap, 
the CIP gives recognition to the nexus between reduc¬ 
tions in long-term usage and reductions in gas supply 
capacity requirements. By limiting any non-weather CIP 
recovery to offsetting gas supply cost reductions, the 
CIP does not just provide the utilities with a mechanism 
for rate recovery but ensures that the CIP results in an 
appropriate, concomitant reduction in gas supply costs 
borne by customers. In this way, customers taking BGSS 
will not incur any overall net rate increases arising from 
non-weather related load losses. 

(New Jersey BPU, 2006) 1 

New Jersey Resources (NJR) recently reported its ex¬ 
perience with the CIP. NJNG, NJR's largest subsidiary, 
realized 6.6 percent increase in its first-quarter earnings 
over last year due primarily to the impact of the recently 
approved CIP. The company states in a recent press 
release that: 

[Our] conservation Incentive Program has performed 
as intended, and has resulted in lower gas costs for 
customers and improved financial results for our shar¬ 
eowners. This innovative program is another example 
of working in partnership with our regulators to help all 
our stakeholders. 

For the three months ended December 31, 2006, 

NJR earned $28.1 million, or $1.01 per basic share, 


National Action Plan for Energy Efficiency 


5-7 


compared with $34.3 million, or $1.24 per basic share, 
last year. The decrease in earnings was due primarily to 
lower earnings at NJR's unregulated wholesale energy 
services subsidiary, NJR Energy Services (NJRES), partially 
offset by improved results at NJNG. NJNG earned $19.9 
million in the quarter, compared with $18.7 million last 
year. The increase in earnings was due to the impact of 
the CIP and continued customer growth. Gross margin 
at NJNG included $11.3 million accrued for future col¬ 
lection from customers under the CIP. 

Weather in the first fiscal quarter was 18.3 percent 
warmer than normal and 18.2 percent warmer than last 
year. "Normal" weather is based on 20-year average 
temperatures. As with the weather normalization clause 
which preceded it, the impact of weather is significantly 
offset by the recently approved CIP, which is designed to 
smooth out year-to-year fluctuations on both gross mar¬ 
gin and customers' bills that may result from changing 
weather and usage patterns. Included in the CIP accrual 
was $8 million associated with the warmer-than-normal 
weather and $3.3 million associated with non-weather 
factors. However, customers will realize annual savings 
of $10.6 million in fixed cost reductions and commodity 
cost savings of approximately $15 million through the 
first fiscal quarter. 

(NJR, 2007) 

5.2.3 Case Study: Baltimore Gas and Electric 

Baltimore Gas and Electric (BGE) has had a form of a 
revenue-per-customer decoupling mechanism in place 
since 1998 for its natural gas business. The Maryland 
PSC allowed BGE to implement a monthly adjustment 
mechanism that accounts for the effect of abnormal 
weather patterns on sales. 

Commission Order 80460 describes Rider 8 8 as follows: 

Rider 8 is a tariff provision that serves as a "weather/ 
number of customers adjustment clause." That is, 
when the weather is warmer, Rider 8 will increase BGE's 
revenues because gas demand is lower than normal. 
However, when the weather is colder than normal and 
gas demand is high, Rider 8 decreases BGE's revenues. 

(Maryland PSC, 2005) 


The mechanism is implemented through the Tariff Rider 
8 or Monthly Rate Adjustment. The following explains 
the mechanism. 

• The delivery price for residential service and for gen¬ 
eral service is adjusted to reflect test year base rate 
revenues established in the latest base rate proceed¬ 
ing, after adjustment to recognize the change in the 
number of customers from the test year level. 

• The change in revenues associated with the customer 
charge is the change in number of customers multi¬ 
plied by the customer charge for the rate schedule. 

• The change in revenues associated with throughput 
is the test year average use per customer multiplied 
by the net number of customers added since the 
like-month during the test year, and multiplying that 
product by the delivery price for the rate schedule. 

• The change in revenues associated with customer 
charge and throughput is added to test year revenue 
to restate test year revenues for the month to include 
the revised values. 

• Actual revenues collected for the month are com¬ 
pared to the restated test year revenues and any 
difference is divided by estimated sales for the second 
succeeding month to obtain the adjustment to the 
applicable delivery price. 

• Any difference between actual and estimated sales is 
reconciled in the determination of the adjustment for 
a future month. 

5.2.4 Case Study: Questar Gas Conservation 
Enabling Tariff 

On December 16, 2005, Questar Gas, the Division of 
Public Utilities, and Utah Clean Energy (UCE) filed an 
application seeking approval of a three-year (pilot) Con¬ 
servation Enabling Tariff (CET) and DSM Pilot Program. 
On September 13, 2006, Questar Gas, the Division, 

UCE, and the committee filed the Settlement Stipula¬ 
tion. The settlement was approved by the commission 
in October 2006 (Utah PSC, 2006). The approval of the 
settlement put in place the CET (Questar Gas, n.d., Sec¬ 
tion 2.11, pages 2-17), which represents the authorized 


5-8 


Aligning Utility Incentives with Investment in Energy Efficiency 


revenue-per-customer amount Questar is allowed to 
collect from General Service customer classes. 

Questar's allowed revenue for a given month is equal 
to the allowed distribution non-gas (DNG) revenue per 
customer for that month multiplied by the actual num¬ 
ber of customers. The difference between the actual 
billed General Services DNG revenue 9 and the allowed 
revenue for that month is the monthly accrual for that 
month. The formula to calculate the monthly accrual is 
shown below. 

allowed revenue (for each month) = 

allowed revenue per customer for that month x 

actual general services customers 

monthly accrual = allowed revenue - actual 

general services DNG revenue 

The accrual could be positive or negative. 

For illustrative purposes, Table 5-4 shows the currently 
allowed DNG revenue per customer for each month 
of 2007. 

For the purpose of keeping track of over- or under¬ 
recovery amounts on a monthly basis, the CET Deferred 
Account (Account 191.9) was established. At least twice 
a year, Questar will file with the commission a request 
for approval for the amortization of the amount accu¬ 
mulated in this account subject to the above formula. 
The amortization will be over a year, and the impacted 
customer class volumetric DNG rates will be adjusted by 
a uniform percentage increase or decrease. The balance 
in the account is subject to 6 percent annual interest 
rate or carrying charge applied monthly (0.5 percent 
each month). 

The settlement states that there would be a 1 -year re¬ 
view of the CET mechanism, and a technical workshop 
would be held in April 2007 commencing the 1-year 
evaluation process. The parties submitted testimony 
either supporting the continuation of the current CET 
mechanism beyond its first year of implementation, 
offering modifications or alternatives, or supporting 
discontinuation of the mechanism on June 1, 2007. 


Table 5-4. Questar Gas DNG Revenue 
per Customer per Month 

Month 

DNG Revenue per Customer 

January 

$42.45 

February 

$34.03 

March 

$26.42 

April 

$20.34 

May 

$13.28 

June 

$10.25 

July 

$10.03 

August 

$9.44 

September 

$10.83 

October 

$15.48 

November 

$26.47 

December 

$36.51 


Source: Questar Gas, n.d. 


In testimony 10 filed by Questar supporting the continu¬ 
ation of the CET, the company stated the following 
benefits of the mechanism: 

•CET allows Questar to collect the commission- 
allowed DNG revenue. During the first year before 
energy efficiency programs were in place, usage 
per customer increased, and over $1.7 million was 
credited back to customers. 

•CET allows Questar to aggressively promote energy 
efficiency, and in 2007 the company launched six 
energy efficiency programs with a budget of about 
$7 million. 

• CET aligns the interests of Questar and regulators for 
the benefit of customers. 

Questar believes that the CET has been working as ex¬ 
pected during its first year of implementation. The Utah 
Committee of Consumer Services filed testimony 11 on 
June 1, 2007, urging the discontinuation of the CET. 
The primary reason driving this recommendation is the 
alleged sales risk shift to consumers with little or no 
offsetting benefits for ratepayers assuming those risks. 


National Action Plan for Energy Efficiency 


5-9 




















As of the writing of this white paper, the proceeding is 
still in process and the commission is expected to reach 
a decision by October of 2007. 

5.3 Lost Revenue Recovery 
Mechanisms _ 

Lost revenue recovery mechanisms 12 are designed 
to recover lost margins that result as sales fall below 
test year levels due to the success of energy efficiency 
programs. They differ from decoupling mechanisms in 
that they do not attempt to decouple revenues from 
sales, but rather try to isolate the amount of under-re¬ 
covery of margin revenues due to the programs. Simply 
put, the margin loss resulting from reductions in sales 
through the implementation of a successful energy effi¬ 
ciency program is calculated as the product of program- 
induced sales reductions and the amount of margin 
allocated per therm or kilowatt-hour in a utility's most 
recent rate case. In this sense, the shortfall in revenue 
recovery is treated as a cost to be recovered. 

Although the disincentive to invest in successful effi¬ 
ciency programs might be removed, lost revenue recov¬ 
ery mechanisms do not remove a utility's disincentive to 
promote/support other energy saving policies, such as 
building codes and appliance standards, or their incen¬ 
tive to see sales increase generally, since the utility still 
earns more profit with additional sales. 

One of the most important characteristics of a lost reve¬ 
nue recovery mechanism is that actual savings achieved 
from a successful energy efficiency program must be 
estimated correctly. Overestimates of savings will en¬ 
able a utility to over-collect, and underestimates lead to 
under-collection of revenue. Unfortunately, reliance on 
evaluation creates two complications: 

• While at its most rigorous, program evaluation pro¬ 
duces a statistically valid estimate of actual savings. 
Rigorous evaluation can be expensive and, in any case, 
will not always be recognized as such by all parties. 

• Because evaluation can only occur after an action 
has occurred, a process built on evaluation is one 


with potentially significant lags built in. It is possible 
to conduct rolling or real-time evaluations, albeit at 
considerable cost. In its least defensible applications, 
such mechanisms are applied with little or no inde¬ 
pendent evaluation and verification. 

Despite these issues, several states have implemented 
lost revenue recovery mechanisms in lieu of decoupling 
as a way to address this barrier. For example, in Janu¬ 
ary 2007, the Indiana Utility Regulatory Commission 
granted Vectren South's application for approval of a 
DSM lost margin adjustment factor for electric service. 13 
Order Nos. 39201 and 40322 accepted the utility's 
request for a lost margin tracking mechanism. Recovery 
is done on a customer class and cost causation basis. 
Vectren South's total demand-side-related lost margin 
to be recovered through rates during the period Febru¬ 
ary to April 2007 was $577,591. 14 

Perceived advantages and disadvantages of the lost rev¬ 
enue recovery mechanism are summarized in Table 5-5. 

5.3.1 Case Study: Kentucky Comprehensive 
Cost Recovery Mechanism 15 

Kentucky currently allows lost revenue recovery for 
both electric and gas DSM programs as part of a 
comprehensive hybrid cost recovery mechanism. Under 
Kentucky Revised Statute 278.190, Kentucky's Public 
Service Commission determines the reasonableness of 
DSM plans that include components for program cost 
recovery, lost revenue recovery, and utility incentives for 
cost-effectiveness. The cost recovery mechanism can be 
reviewed as part of a rate proceeding, or as part of a 
separate, limited proceeding. 

The DSM Cost Recovery Mechanism currently in ef¬ 
fect for Louisville Gas and Electric Company (LG&E) 
is composed of factors for DSM program cost recov¬ 
ery (DCR), DSM revenue from lost sales (DRLS), DSM 
incentive (DSMI), and DSM balance adjustment (DBA). 
The monthly amount computed under each of the rate 
schedules to which this DSM Cost Recovery Mechanism 
applies is adjusted by the DSM Cost Recovery Compo¬ 
nent (DSMRC) at a rate per kilowatt-hour of monthly 
consumption in accordance with the following formula: 


5-10 


Aligning Utility Incentives with Investment in Energy Efficiency 











• Does not remove the throughput incentive to increase sales. 

• Does not remove the disincentive to support other energy saving policies. 

• Can be complex to implement given the need for precise evaluation, and will increase regulatory costs if it is 
closely monitored. 

• Proper recovery (no over- or under-recovery) depends on precise evaluation of program savings 


DSMRC = DCR + DRLS + DSMI + DBA 

The DCR includes all expected costs approved by the 
commission for each 12-month period for DSM pro¬ 
grams, including costs for planning, developing, imple¬ 
menting, monitoring, and evaluating DSM programs. 
Only those customer classes to which the programs are 
offered are subject to the DCR. The cost of approved 
programs is divided by the expected kilowatt-hour sales 
for the next 12-month period to determine the DCR for 
a given rate class. 

• For each upcoming 12-month period, the estimated 
reduction in customer usage (in kilowatt-hours) ' 

as determined for the approved programs shall be 
multiplied by the nonvariable revenue requirement 
per kilowatt-hour for purposes of determining the 
lost revenue to be recovered hereunder from each 
customer class. 

• The nonvariable revenue requirement for the Residential 
and General Service customer class is defined as the 
weighted average price per kilowatt-hour of expected 
billings under the energy charges contained in the rate 
RS, VFD, RPM, and General Services rate schedules in 
the upcoming 12-month period, after deducting the 
variable costs included in such energy charges. 

• The nonvariable revenue requirement for each of 
the customer classes that are billed under demand 
and energy rates (rates STOD, LC, LC-TOD, LP, and 


LP TOD) is defined as the weighted average price per 
kilowatt-hour represented by the composite of the 
expected billings under the respective demand and 
energy charges in the upcoming 12-month period, 
after deducting the variable costs included in the 
energy charges. 

• The lost revenues for each customer class shall then be 
divided by the estimated class sales (in kilowatt-hour) 
for the upcoming 12-month period to determine the 
applicable DRLS surcharge. 

• Recovery of revenue from lost sales calculated for a 
12-month period shall be included in the DRLS for 36 
months or until implementation of new rates pursu¬ 
ant to a general rate case, whichever comes first. 

• Revenues from lost sales will be assigned for recovery 
purposes to the rate classes whose programs resulted 
in the lost sales. 

• Revenues collected under the mechanism are based 
on engineering estimates of energy savings, expected 
program participation and estimated sales for the 
upcoming 12-month period. At the end of each such 
period, any difference between the lost revenues 
actually collected hereunder, and the lost revenues 
determined after any revisions of the engineering es¬ 
timates and actual program participation are account¬ 
ed for, shall be reconciled in future billings under the 
DBA component. 


National Action Plan for Energy Efficiency 


5-11 








I 


DSMI is calculated by multiplying the net resource sav¬ 
ings expected from the approved programs expected to 
be installed during the next 12-month period by 15 per¬ 
cent, not to exceed 5 percent of program expenditures. 
Net resource savings are equal to program benefits 
minus utility program costs and participant costs. Pro¬ 
gram benefits are calculated based on the present value 
of LG&E's avoided costs over the expected program life 
and includes capacity and energy savings. 

The DBA is calculated for each calendar year and is 
used to reconcile the difference between the amount 
of revenues actually billed through the DCR, DRLS, 

DSMI, and previous application of the DBA. The balance 
adjustment (BA) amounts include interest applied to the 
bill amount calculated as the average of the "3-month 
commercial paper rate" for the immediately preceding 
12-month period. The total of the BA amounts is di¬ 
vided by the expected kilowatt-hour sales to determine 
the DBA for each rate class. DBA amounts are assigned 
to the rate classes with under- or over-recoveries of 
DSM amounts. 

The levels of the various DSM cost recovery components 
effective April 3, 2007, for LG&E's residential customers 
are shown in the Table 5-6. 

5.4 Alternative Rate Structures 

The lost margin issue arises because some or all of a 

utility's current fixed costs are recovered through volu- 

\ 

metric charges. The most straightforward resolution 
to the issue is to design and implement rate structures 
that allocate a larger share of fixed costs to customer 
fixed charges. SFV rate structures allocate all current 
fixed costs to a per customer charge that does not 
vary with consumption. Alternatives to the SFV design 
employ a consumption block structure, which allocates 
costs across several blocks of commodity consumption 
and typically places most or all of the fixed costs within 
the initial block. This block is designed such that most 
customers will always consume more than this amount 
and, therefore, fixed costs will be recovered regard¬ 
less of the level of sales in higher blocks (American Gas 


Table 5-6. Louisville Gas and Electric 
Company DSM Cost Recovery Rates 

DSM cost recovery 
component (DCR) 

0.085 c/kilowatt-hour 

DSM revenues from 
lost sales (DRLS) 

0.005 c/kilowatt-hour 

DSM incentive 
(DSMI) 

0.004 c/kilowatt-hour 

DSM balance 
adjustment (DBA) 

(0.010)c/kilowatt-hour 

DSMRC rates 

0.084 c/kilowatt-hour 


Source: LG&E, 2004. 


Association, 2006b). This produces a declining block 
rate structure. 

Such a rate design provides significant earnings stabil¬ 
ity for the utility in the short run, making it indifferent 
from a net revenue perspective to the customer's usage 
at any time. In this way, these alternative rate structures 
are similar to revenue decoupling; a utility has neither 
a disincentive to promote energy efficiency nor an 
incentive to promote increased sales. SFV and similar 
rate designs also are viewed by some as adhering more 
closely to a theoretically correct approach to cost alloca¬ 
tion that sees fixed costs as a function of the number of 
customers or the level of customer demand. 

This approach is most commonly discussed in the con¬ 
text of natural gas distribution companies, where fixed 
costs represent the costs to build out and maintain a 
distribution system. These costs tend to vary more as 
a function of the number of customers than of system 
throughput (American Gas Association, 2006c). 16 These 
alternative rate designs are more problematic when ap¬ 
plied to integrated electric utilities, because fixed costs 
are in some cases related to the volume of electricity 
consumed. For example, the need for baseload capacity 
is driven by the level of energy consumption as much 
or more than by the level of peak demand. Practically, 
it is more difficult to allocate all fixed costs to a fixed 
customer charge, simply because such costs can be very 


5-12 


Aligning Utility Incentives with Investment in Energy Efficiency 










Table 5-7. Pros and Cons of Alternative Rate Structures 



• May not align with cost causation principles for integrated utilities, especially in the long run. 

• Can create issues of income equity. 

• Movement to a SFV design can significantly reduce customer incentives to reduce consumption by lowering 
variable charges (applies more to electric than gas utilities). 


high, and allocation to a fixed charge would impose 
serious ability-to-pay issues on lower income custom¬ 
ers. Nevertheless, improvements in rate structures that 
better align energy charges with the marginal costs of 
energy will help reduce the throughput disincentive. 

Given the overarching objective of capturing the net 
economic and environmental benefits of energy efficiency 
investments, SFV designs can significantly reduce a cus¬ 
tomer's incentive to undertake efficiency improvements 
because of the associated reduction in variable charges. 

5.5 Notes 

1. Also known as lost revenue or lost margin recovery. 

2. The National Action Plan for Energy Efficiency. 

3. Also see Chapter 6, "Utility Planning and Incentive Structures," 
in the EPA Clean Energy-Environment Guide to Action. 

4. The Idaho Public Utilities Commission adopted a three-year 
decoupling pilot in March 2007, and in April 2007, the New 
York Public Service Commission ordered electric and natural gas 
utilities to file decoupling plans within the context of ongoing 
and new rate cases. The Minnesota legislature recently (spring 
2007) enacted legislation authorizing decoupling. List of states is 
taken from the Natural Resources Defense Council's map of Gas 
and Electric Decoupling in the US, June 2007. 

5. The design of the decoupling mechanism can address risk- 
shifting through the nature of the adjustments that are included. 
Some states have explicitly not included weather-related fluctua¬ 
tions in the decoupling mechanism (the utility continues to bear 
weather risk). In addition, recognizing that utility shareholder 


risk decreases with decoupling, some decoupling plans include 
provisions for capturing some of the risk reduction benefits for 
consumers. For example, PEPCO proposed (and subsequently 
withdrew a proposal for a 0.25 percent reduction in its ROE 
to reflect lower risk. The issue is under consideration by the 
Delaware Commission in a generic decoupling proceeding. The 
Oregon Public Utilities Commission reduced the threshold above 
which Cascade Natural Gas must share earnings from baseline 
ROE plus 300 basis points, to baseline ROE plus 175 basis points. 

6. The impact of decoupling in eliminating the throughput incen¬ 
tives is lessened as the scope of the decoupling mechanism 
shrinks. 

7. Note, however, that as the various determinants of sales, such as 
weather and economic activity, are excluded from the mecha¬ 
nism, the need for complex adjustment and evaluation methods 
increases. In any case, an evaluation process should nevertheless 
be part of the broader energy efficiency investment process. 

8. <www.bge.com/vcmfiles/BGE/Files/Rates%20and%20Tariffs/ 
Gas%20Service%2 Tariff/Brdr_3.doc>. 

i 

9. Customers' bills include a real-time, customer-specific Weather 
Normalization Adjustment (see Section 2.08 of Questar Gas, 
n.d.) to eliminate the impact of warmer or colder than normal 
weather on the DNG portion of the bill. 

10. Direct Testimony of Barrie L. McKay to Support the Continuation of 
the Conservation Enabling Tariff for Questar Gas Company, Docket 
No. 05-057-T01, June 1, 2007, accessed at <www.psc.utah.gov/ 
gas/05docs/05057T01/535586-1-07DitTestBarrieMcKay.doc>. 

11. Direct Testimony of David E. Dismukes, Ph.D., on Be¬ 
half of the Utah Committee of Consumer Services, 

Docket No. 05-057-T01, June 1, 2007, accessed 

at <www.psc.utah.gov/gas/05docs/05057T01/6-1- 
0753584DirTestDavidDismukesPh.D.doc>. 


National Action Plan for Energy Efficiency 


5-13 








12. Also known as lost revenue or lost margin recovery mechanisms. 

13. Order issued in Cause No. 39453 DSM 59 on January 31, 2007, 
accessed at <www.in.gov/iurc/portal/Modules/Ecms/Cases/ 
Docketed_Cases/ViewDocumentaspx?DoclD=0900b631800 
c5033>. 

14. Energy efficiency traditionally has been'defined as an overall 
reduction in energy use due to use of more efficiency equipment 
and practices, while load management, as a subset of demand 
response has been defined as reductions or shifts in demand with 
minor declines and sometimes increases in energy use. 

15. This description quotes extensively from LG&E, 2004. 

16. Even m a gas distribution system, fixed costs do vary partly as a 
function of individual customer demand. The SFV rate used by 
Atlanta Gas Light, for example, estimates the fixed charge as a 
function of the maximum daily demand for gas imposed by each 
premise. 


5-14 


Aligning Utility Incentives with Investment in Energy Efficiency 











I Performance Incentives 



This chapter provides a practical overview of alternative performance incentive mechanisms and presents 
their pros and cons. Detailed case studies are provided for each mechanism. 


6.1 Overview 

The final financial effect is represented by incentives 
provided to utility shareholders for the performance of 
a utility's energy efficiency programs. Even if regulatory 
policy enables recovery of program costs and addresses 
the issue of lost margins, at best, two major disincen¬ 
tives to promotion of energy efficiency are removed. 
Financially, demand- and supply-side investments are 
still not equivalent, as the supply-side investment will 
generate greater earnings. However, the availabil¬ 
ity of performance incentives can establish financial 


equivalence and creates a clear utility financial interest 
in the success of efficiency programs. 

Three major types of performance mechanisms have 
been most prevalent: 

• Performance target incentives 

• Shared savings incentives 

• Rate of return incentives 

Table 6-1 illustrates the various forms of performance 
incentives in effect today. 


Table 6- 

1. Examples of Utility Performance Incentive Mechanisms 

State 

Type of Utility Performance 
Incentive Mechanism 

Details 

AZ 

Shared savings 

Share of net economic benefits up to 10 percent of 
total DSM spending. 

CT 

Performance target 

Savings and other programs goals 

Management fee of 1 to 8 percent of program costs 
(before tax) for meeting or exceeding predetermined 
targets. One percent incentive is given to meet at least 
70 percent of the target, 5 percent for meeting the 
target, and 8 percent for 130 percent of the target. 

GA 

Shared savings 

! 

15 percent of the net benefits of the Power Credit 

Single Family Home program. 

HI 

Shared savings 

Hawaiian Electric must meet four energy efficiency 
targets to be eligible for incentives calculated based 
on net system benefits up to 5 percent. 


National Action Plan for Energy Efficiency 


6-1 















X 


Table 6-1. Examples of Utility Performance Incentive Mechanisms (continued) 

State 

Type of Utility Performance 
Incentive Mechanism 

Details 

IN 

Shared savings/rate of return 
(utility-specific) 

Southern Indiana Gas and Electric Company may earn 
up to 2 percent added ROE on its DSM investments if 
performance targets are met with one percent pen¬ 
alty otherwise. 

KS 

Rate of return incentives 

2 percent additional ROE for energy efficiency invest¬ 
ments possible. 

MA 

Performance target 

Multi-factor performance targets, savings, 
value, and performance 

5 percent of program costs are given to the distribu¬ 
tion utilities if savings targets are met on a program- 
by-program basis. 

MN 

Shared savings 

Energy savings goal 

Specific share of net benefits based on cost-effective¬ 
ness test is given back to the utilities. At 150 percent 
of savings target, 30 percent of the conservation 
expenditure budget can be earned. 

MT 

Rate of return incentives 

2 percent added ROE on capitalized demand response 
programs possible. 

NV 

Rate of return incentives 

5 percent additional ROE for energy efficiency invest¬ 
ments. 

NH 

Shared savings 

Savings and cost- effectiveness goals 

Performance incentive of up to 8 to 12 percent of 
total program budgets for meeting cost-effectiveness 
and savings goals. 

Rl 

Performance targets 

Savings and cost- effectiveness goals 

Five performance-based metrics and savings targets 
by sector. Incentives from at least 60 percent of sav¬ 
ings target up to 125 percent. 

SC 

N/A 

Utility-specific incentives for DSM programs allowed. 


Notes: For AZ, CT, MA, MN, NV, NH, and Rl, see Kushler, York, and Witte, 2006. 


For IN, KS, and SC, see Michigan PUC, 2003. 

For HI, see Hawaii PUC, 2007. Note that in a prior order the Hawaii Commission eliminated specific shareholder incentives and fixed-cost recovery. 
However, in the instant case, the commission was persuaded to provide a shared savings incentive. 

Vermont uses an efficiency utility, Efficiency Vermont, to administer energy efficiency programs. While not a utility in a conventional sense, 
Efficiency Vermont is eligible to receive performance incentives. 


6-2 


Aligning Utility Incentives with Investment in Energy Efficiency 




















6.2 Performance Targets 

Mechanisms that allow utilities to capture some portion 
of net benefits typically include savings performance 
targets. Incentives are not paid unless a utility achieves 
some minimum fraction of proposed savings, and 
incentives are capped at some level above projected 
savings. 1 Several states have designed multi-objective 
performance mechanisms. Utilities in Connecticut, for 
example, are eligible for "performance management 
fees" tied to performance goals such as lifetime energy 
savings, demand savings, and other measures. Incen¬ 
tives are available for a range of outcomes from 70 to 
130 percent of pre-determined goals. A utility is not 
entitled to the management fee unless it achieves at 
least 70 percent of the targets. After 130 percent of 
the goals have been reached, no added incentive is 
provided. Over the incentive-eligible range of 70 to 130 
percent, the utilities can earn 2 to 8 percent of total 
energy efficiency program expenditures. 

6.2.1 Case Study: Massachusetts 

The Massachusetts Department of Telecommunications 
and Energy Order in Docket 98-100 (February 2000) 2 
allows for performance-based performance incentives 
where a distribution company achieves its "design" per¬ 
formance level (i.e., the energy efficiency program per¬ 
formance level that the distribution company expects to 
achieve). The performance tiers are defined as follows: 

1. The design performance level represents the level 
of performance that the distribution utility expects 
to achieve from the implementation of the energy 
efficiency programs included in its proposed plan. 

The design performance level is expressed in terms 
of levels of savings in energy, commodity, and 
capacity, and in other measures of performance as 
appropriate. 

2. The threshold performance level (the minimum level 
that must be achieved for a utility to be eligible for 
an incentive) represents 75 percent of the utility's 
design performance level. 


3. The exemplary performance level represents 125 
percent of the utility's design performance level. 

For the distribution utilities that achieve their design 
performance levels, the after-tax performance incentive 
is calculated as the product of: 3 

1. The average yield of the 3-month United States Trea¬ 
sury bill calculated as the arithmetic average of the 
yields of the 3-month United States Treasury bills is¬ 
sued during the most recent 12-month period, or as 
the arithmetic average of the 3-month United States 
Treasury bill's 12-month high and 12-month low, and 

2. The direct program implementation costs. 

A distribution utility calculates its after-tax performance 
incentive as the product of: 

1. The percentage of the design performance level 
achieved, and 

2. The design performance incentive level, provided 
that the utility will earn no incentive if its actual per¬ 
formance is below its threshold performance level, 
and will earn no more than its exemplary perfor¬ 
mance level incentive even if its actual performance 
is beyond its exemplary performance level. 

In May 2007, the Massachusetts Department of Pub¬ 
lic Utilities issued an order approving NSTAR Electric's 
Energy Efficiency Plan for calendar year 2006, filed with 
the department in April 2006 4 NSTAR Electric's utility 
performance incentive proposal contains performance 
categories based on savings, value, and performance 
determinants and allocates specific weights to each 
category. For its residential programs, NSTAR Electric 
allocates the weights for its savings, value, and perfor¬ 
mance determinants as follows: 45 percent, 35 percent, 
and 20 percent, respectively. For its low-income pro¬ 
grams, the weights are 30 percent, 10 percent, and 60 
percent, respectively. And for its commercial and indus¬ 
trial programs, NSTAR sets the weights at 45 percent, 

35 percent, and 20 percent, respectively. 5 

NSTAR proposed an incentive rate equal to 5 percent (af¬ 
ter tax) of net benefits, as opposed to the pre-approved 


National Action Plan for Energy Efficiency 


6-3 


/> 


3-Month Treasury rate, and also requested that the 
exemplary performance level be set at 110 percent 
of design level for 2006 rather than the 125 percent 
threshold set by the department. The department ac¬ 
cepted both changes. With regard to the latter, the 
department noted that the precision of performance 
measurements had improved to the point that perfor¬ 
mance could be forecast more accurately. Based on 
these parameters, the company estimated its annual 
incentive would be $2.4 million. 6 

6.3 Shared Savings _ 

With a shared savings mechanism, utilities share the net 
benefits resulting from successful implementation of en¬ 
ergy efficiency programs with ratepayers. Implicitly, net 
benefits are tied to the utility's avoided costs, as these 
costs determine the level of economic benefit achieved. 
Therefore, the potential upside to a utility from use of a 
shared savings mechanism will be greater in jurisdictions 
with higher avoided costs. 7 Key elements in fashioning 
a shared savings mechanism include: 

• The degree of sharing (the percentage of net benefits 
retained by a utility). 

• The amount to be shared (maximum dollar amount of 
the incentive irrespective of the sharing percentage). 

• The extent to which there are penalties for failing to 
reach performance targets. 

• The manner in which avoided costs are determined for 

purposes of calculating net benefits. , 

• The threshold values above which the sharing will 
begin. 

6.3.1 Case Study: Minnesota 

Minnesota Statute § 216B.241 8 requires Minnesota's 
energy utilities to invest in energy conservation im¬ 
provement programs (CIP) authorized by the Minne¬ 
sota Department of Commerce. Utilities are allowed to 
recover their costs annually. Part of the CIP cost recov¬ 
ery is achieved through a conservation cost recovery 
charge (CCRC). If a utility's CIP costs differ from the 


amount recovered through the CCRC, the utility can 
adjust its rates annually through the conservation cost 
recovery adjustment (CCRA). Utilities record CIP costs 
in a "tracker" account. The Minnesota Public Utilities 
Commission reviews these accounts before the utilities 
are authorized to make adjustments to their rates. The 
statute also authorizes the commission to provide an 
incentive rate of return, a shared savings incentive, and 
lost margin/fixed cost recovery. 

The legislation describes the requirements of an incentive 
plan as follows: 

Subd. 6c. Incentive plan for energy conservation 

improvement. 

(a) The commission may order public utilities to develop and 
submit for commission approval incentive plans that de¬ 
scribe the method of recovery and accounting for utility 
conservation expenditures and savings. In developing the 
incentive plans the commission shall ensure the effective 
involvement of interested parties. 

(b) In approving incentive plans, the commission shall 
consider: 

(1) Whether the plan is likely to increase utility invest¬ 
ment in cost-effective energy conservation. 

(2) Whether the plan is compatible with the interest of 
utility ratepayers and other interested parties. 

(3) Whether the plan links the incentive to the utility's 
performance in achieving cost-effective conservation. 

(4) Whether the plan is in conflict with other provisions 
of this chapter. 

As explained in the Order Approving DSM Financial 
Incentive Plans under Docket E, G-999/CI-98-1759, 9 
issued in April 2000, Minnesota Public Utilities Commis¬ 
sion convened a round table in December 1998 to as¬ 
sess gas and electric DSM efforts "to identify other DSM 
programs and methodologies that effectively conserve 
energy, to revaluate the need for gas and electric DSM 
financial incentives and make recommendations for 
elimination or redesign." 


6-4 


Aligning Utility Incentives with Investment in Energy Efficiency 


In November 1999, a joint proposal for a shared savings 
D5M financial incentive plan was filed with the commis¬ 
sion. In the same month, each of the utilities filed their 
proposed DSMI plans for 1999 and beyond. 

The jointly proposed DSM financial incentive plan, which 
formed the basis for individual utility plans, was intended to 
replace the then current incentive plans. A primary char¬ 
acteristic of the proposed plan was the method for deter¬ 
mining a utility's target energy savings used to calculate 
incentives. Each utility was subject to the same following 
formula in determining the energy savings goal: 

(approved energy savings goal -f approved budget) x 
statutory minimum spending level 

i 

where the statutory spending requirement is 1 percent 
for electric lOUs (Xcel at 2 percent) and 0.5 percent for 
gas utilities. 

The utilities were required to show that their expendi¬ 
tures resulted in net ratepayer benefits (utility program 
costs netted against avoided supply-side costs). The net 
benefits of achieving the specific percentage of en¬ 
ergy savings goals were calculated by determining the 
utilities' avoided costs resulting from their actual CIP 
achievement, then subtracting the CIP costs. A portion 
of these benefits was given to the shareholders as an 
incentive. The size of the incentive depended on the 
percentage of the net benefits achieved. This percent¬ 
age increased as the percentage of the goal reached 
increased. At 90 percent of the goal, the utility received 
no incentive. At 91 percent of the goal, a small percent¬ 
age of its net benefits were given to the utility. Net ben¬ 
efits, as mentioned, depended on the utility's avoided 
costs, which varied from utility to utility. In order to treat 
all utilities equally, the percentage values were calcu¬ 
lated such that at 150 percent of the goals, the utility's 
incentive was capped at 30 percent of its statutory 
spending requirement. 

In the April 7, 2000 order, the commission found 
that the plan was likely to increase investment in 
cost-effective energy conservation. The incentive 
grew for each incremental block of energy savings. 

: No significant incentive was provided unless a utility 


met or exceeded its expected energy savings at mini¬ 
mum spending requirements. 10 The mechanism was 
designed such that if a utility's program was not cost- 
effective (i.e., there were no net benefits), no incen¬ 
tives were paid. As the cost-effectiveness increased, net 
benefits and incentives increased accordingly. 

The utilities make compliance filings on February 1 of 
each year to demonstrate the application of the incen¬ 
tive mechanism to a utility's budget and energy savings 
target. 

The 2007 compliance filing 11 of Northern States Power 
Company (NSP), a wholly owned subsidiary of Xcel En¬ 
ergy, offers useful insight into application of the electric 
and gas incentive mechanism, in this case incorporating 
goals and budgets approved in November 2006. Table 
6-2 shows the basic calculation of net benefits, and 
Table 6-3 shows the incentive amount earned by NSP at 
different levels of program savings. 

6.3.2 Case Study: Hawaiian Electric Company 
(HECO) 

In Order No. 23258, the Hawaii Public Utilities Commis¬ 
sion approved HECO's proposed energy efficiency incen¬ 
tive mechanism. The order sets four energy efficiency 
goals that HECO must meet before being entitled to 
any incentive based on net system benefits (less pro¬ 
gram costs). Only positive incentives are allowed; in 
other words, once HECO meets and exceeds the energy 
efficiency goals, it is entitled to the incentive, but if it 
cannot achieve the goal, no penalties will apply. 

The order details the approach as follows: 

The DSM Utility Incentive Mechanism will be calculated 
based on net system benefits (less program costs), 
limited to no more than the utility earnings opportuni¬ 
ties foregone by implementing DSM programs in lieu 
of supply-side rate based investments, capped at $4 
million, subject to the following performance require¬ 
ments and incentive schedule. As indicated in section 
III.E.I.c., supra, the commission is not requiring nega¬ 
tive incentives. In order to encourage high achieve¬ 
ment, HECO must meet or exceed the megawatt-hour 
and megawatt Energy Efficiency goals for both the 


National Action Plan for Energy Efficiency 


6-5 


T 


Table 6-2. Northern States Power Net Benefit Calculation 

2007 Inputs 

Electric 

Gas 

Approved CIP energy (kWh/MCF) 

238,213,749 

729,086 

Approved CIP budget (S) 

45,504,799 

5,239,557 

Minimum spending 3 ($) 

42,147,472 

3,718,065 

Energy savings @ 100% of goal b (kWh/MCF) 

220,638,428 

517,370 

• 

Estimated net benefits 0 ($) 

180,402,782 

65,813,455 

Net benefits @ 100% of goal d (S) 

167,092,732 

46,702,175 


(a) Statutory requirement. Electric: 2 percent of gross operating revenue. Gas: 0.5 percent. 

(b) Energy savings at 100 percent of goal: (Minimum Spending x Goal Energy Savings) -r Goal Spending. 


(c) Estimated net benefits are calculated from the approved cost-benefit analysis in the 2007/2008/2009 CIP Triennial Plan. For electric, estimated net 
benefits are equal to the sum of each program's total avoided costs minus spending. For gas, the estimated net benefit is equal to total gas CIP rev¬ 
enue requirements test NPV for 2007 as first and only year. 

(d) Net benefits at 100 percent of goal = (Minimum Spending x Goal Net Benefits) Goal Spending. 


Table 6-3. Northern States Power 2007 Electric Incentive Calculation 


Electric 

Kilowatt-Hour 

Percent 
of Base 

Estimated 
Benefits Achieved 

Estimated 

Incentive 

90% of goal 

198,574,585 

0.00% 

150,383,459 

0 

100% of goal 

220,638,428 

0.8408% 

167,092,732 

1,404,916 

110% of goal 

242,702,270 

1.6816% 

183,802,005 

3,090,815 

120% of goal 

264,766,113 

2.5224% 

200,511,278 

5,057,697 

130% of goal 

286,829,956 

3.3632% 

217,220,552 

7,305,562 

140% of goal 

308,893,799 

4.2040% 

233,929,825 

9,834,410 

150% of goal 

330,957,641 

5.0448% 

250,639,098 

12,644,241 


Source: Xcel Energy, 2006. 


6-6 


Aligning Utility Incentives with Investment in Energy Efficiency 



































commercial and industrial sector, and the residential 
sector, established in section III.A., supra, for HECO to 
be eligible for a DSM utility incentive. If HECO fails to 
meet one or more of its four Energy Efficiency goals, 
see supra section III.A.8., HECO will not be eligible to 
receive a DSM utility incentive. Upon a determination 
that HECO is eligible for a DSM utility incentive, the 
next step will be to calculate the percentage by which 
HECO's actual performance meets or exceeds each of 
its Energy Efficiency goals. Then, these four percentages 
will be averaged to determine HECO's "Averaged Actual 
Performance Above Goals." 

(Hawaii PUC, 2007) 

The incentive allowed HECO (as a percentage of net 
benefits) is a function of the extent to which the 
company exceeds its savings goals, as illustrated by 
Table 6-4. 

The commission also provided the following example to 
illustrate how the mechanism works. 

Assume that HECO's 2007 actual total gross commercial 
and industrial energy savings is 100,893 megawatt- 
hours, HECO's 2007 actual total gross residential energy 
savings is 50,553 megawatt-hours, HECO's 2007 actual 
total gross commercial and industrial demand savings is 
13.416 megawatts, and HECO's 2007 actual total gross 
residential energy savings is 14.016 megawatts. 

(Hawaii PUC, 2007) 

6.3.3 Case Study: The California Utilities 

In September 2007, CPUC adopted a far-reaching util¬ 
ity performance incentives plan that creates both the 
potential for significant additions to utility earnings for 
superior performance, and significant penalties for inad¬ 
equate performance. 

Under the plan, shareholder incentives are tied to utili¬ 
ties' independently verified achievement of CPUC-estab- 
lished savings goals for each three-year program cycle 
and to the level of verified net benefits. Savings goals 


Table 6-4. Hawaiian Electric Company 
Shared Savings Incentive Structure 


Meets goal 

1% 

Exceeds goal by 2.5% 

2% 

Exceeds goal by 5% 

3% 

Exceeds goal by 7.5% 

4% 

Exceeds goal by 10.0% 
or more 

5% 


Source: Hawaii PUC, 2007. 


have been established for kilowatt-hours, kilowatts, 
and therms. To be eligible for an incentive, utilities must 
achieve at least 80 percent of each applicable savings 
goal. 12 If utilities achieve 85 percent and up to 100 
percent of the simple average of all applicable goals, 
shareholders will receive a reward of 9 percent of veri¬ 
fied net benefits. 13 Achievement of over 100 percent 
or more of the goal will yield a performance payment 
of 12 percent of verified net benefits, with a statewide 
cap of $450 million over each three-year program cycle. 
Failure to achieve at least 65 percent of goal will result 
in performance penalties. Penalties are calculated as the 
greater of a charge per unit (kilowatt-hour, kilowatt, or 
therm) for shortfalls at or below 65 percent of goal, or 
a dollar-for-dolla'r payback to ratepayers of any negative 
net benefits. Total penalties also are capped statewide 
at $500 million. A performance dead-band of between 
65 percent and 85 percent of goal produces no per¬ 
formance reward or penalty. Figure 6-1 and Table 6-6 
illustrate the incentive structure. 

For example, if utilities achieve the threshold 85 percent 
of goal for the current 2006-2008 program period, and 
total verified net benefits equal the estimated value 
of $1.9 billion on a statewide basis, the utilities would 


Averaged Actual 
Performance 
Above Goals 


DSM Utility Incentive 
(% of Net System 
Benefits) 


National Action Plan for Energy Efficiency 


6-7 













Table 6-5. Illustration of HECO Shared Savings Calculation 


Energy Efficiency Energy 
Savings (MWh) 

2007 

Goal 

(MWh) 

2007 Actual 
Performance 
(MWh) 

Energy Efficiency 
Goal Met? 

Actual Performance 
Above 2007 Goal 
(%) 

Commercial and industrial 





Total gross energy savings 

91,549 

100,893 

10.21% 

Yes 

Residential 





Total gross energy savings 

50,553 

50,553 

Yes 

0% 

• 

Commercial and industrial 





Total gross demand savings 

13.041 

13.416 

Yes 

2 . 88 % 

Residential 





Total gross demand savings 

13.336 

14.016 

Yes 

5 . 10 % 

Averaged actual performance 
above goals 

4.55% 




DSM utility incentive 
(% of net system benefits) 

2% 





Source: Hawaii PUC, 2007. 


receive 9 percent of that amount, or $175 million. If the 
utilities each met 100 percent of the savings goals, and 
the estimated verified net benefit of $2.7 billion is real¬ 
ized, the earnings bonus would equal $323 million. 

Rewards or penalties may be collected in three install¬ 
ments for each three-year program cycle. Two interim 
reward claims or penalty assessments will be made 


based on estimated performance and net benefits. The 
third payment—a "true-up claim"—will be made after 
the program cycle is complete and savings and net ben¬ 
efits have been independently verified. Thirty percent of 
each interim reward payment is withheld to cover po¬ 
tential errors in estimated earnings calculations. Verified 
savings will be based on independent measurement and 
evaluation studies managed by CPUC. 


6-8 


Aligning Utility Incentives with Investment in Energy Efficiency 
























Figure 6-1. California Performance Incentive Mechanism Earnings/ 

Penalty Curve 

a Earnings capped at $450 

million 


Reward 

(% of PEB) 


0% 


ER = 12% 


ER = 9% 


► 


I 


65% 85% 100% 

I 


-► 

% of CPUC goals 


(per unit below 
CPUC goal) 

Penalty 


5?/kWh, $25/kW, 45«/therm below 
goals, or payback of negative net 
benefits (cost-effectiveness guarantee), 
whichever is greater 


Penalty capped at $450 
million 


Earnings = ER x PEB 

PEB = Performance Earnings Basis 

ER = Earnings Rate (or 5hared-Savings Rate) 


t 

Source: CPUC, 2007. 


CPUC also adjusted the basic cost-effectiveness calcu¬ 
lations for purposes of determining net benefits. The 
estimated value of the performance incentives must 
be treated as a cost in the net benefit calculation, both 
during the program planning process to determine 
the overall cost-effectiveness of the utilities' energy 
efficiency portfolios, and when the value of net benefits 
is calculated for purposes of reward determinations 
subsequent to program implementation. 

The commission devoted a significant portion of its 
order to the fundamental issues surrounding utility 


performance incentives—whether and why a utility 
should earn rewards for what are essential expenditures 
of ratepayer funds; the basis for determining the magni¬ 
tude of the shareholder rewards; and the relationship 
between relative reward levels and performance. CPUC 
ultimately concluded that incentives were appropriate 
and necessary to achieve the ambitious energy effi¬ 
ciency goals the utilities had been given. The rewards at 
high levels of goal attainment were set to be generally 
reflective of earnings from supply-side investments fore¬ 
gone due to implementation of the energy efficiency 
programs. 


National Action Plan for Energy Efficiency 


6-9 











Table 6-6. Ratepayer and Shareholder Benefits Under California’s Shareholder 
Incentive Mechanism (Based on 2006-2008 Program Cycle Estimates) 

Verified Savings % 
of Goals 

Total Verified Net 
Benefits 

Shareholder Earnings 

Ratepayers' Savings 

125% 

$2,919 

$450 

cap 

$3,469 

120% 

$3,673 

$441 


$3,232 

115% 

$3,427 

$411 


$3,016 

110% 

$3,181 

$382 


$2,799 

105% 

$2,935 

$352 


$2,583 

100% 

$2,689 

$323 


$2,366 

95% 

$2,443 

$220 


$2,223 

i 

90% 

$2,197 

$198 


$1,999 

85% 

$1,951 

$176 


$1,775 

80% 

$1,705 

$0 


$1,705 

75% 

$1,459 

$0 


$1,459 

70% 

$1,213 

$0 


$1,213 

65% 

$967 

($144) 


$1,111 

60% 

$721 

($168) 


$889 

55% 

$475 

($199) 


$674 

50% 

$228 

($239) 


$467 

45% 

($18) 

($276) 


$258 

40% 

($264) 

($378) 


$114 

35% 

($510) 

($450) 

cap 

■ ($60) 


Source: CPUC, 2007. 


6-10 


Aligning Utility Incentives with Investment in Energy Efficiency 































Finally, the structure of what the commission termed 
the "earnings curve," showing the relationship between 
goal achievement and reward and penalty levels, was 
fashioned to achieve a reasonable balance between 
opportunity for reward and risk for penalty. And al¬ 
though potential penalties are significant, even in cases 
in which programs deliver a net benefit (but fail to meet 
goal), CPUC found that utilities have sufficient ability 
to manage these risks, such that penalties can reason¬ 
ably be associated with nonperformance as opposed to 
uncontrollable circumstances. This last point has been 
contested. Utilities are subject to substantial evaluation 
risk in the final true-up claim. An evaluator's finding 
that per-unit measure savings or net-to-gross ratios 14 
were significantly lower than those estimated ex ante 
(thus significantly lowering system net benefits) could 
result in utilities having to refund interim performance 
payments, which are based on estimates of net ben¬ 
efits. While utilities have some control over net-to-gross 
ratios through program design, there is considerable 
debate over the reliability of net-to-gross calculations, 
and even if utilities attempt to monitor the level of free 
ridership in a program, the final findings of an indepen¬ 
dent evaluator are unpredictable. 

6.4 Enhanced Rate of Return 

Under the bonus rate of return mechanism, utilities are 
allowed an increased return on investment for energy 
efficiency investments or offered a bonus return on total 
equity investment for superior performance. A number 
of states allowed an increased rate of return on energy 
efficiency-related investments starting in the 1980s. In 
fact, the majority of the states that allowed or required 
ratebasing or capitalization also allowed an increased 
rate of return for such investments. For example, 
Washington and Montana allowed an additional 2 
percent return for energy efficiency investments, while 
Wisconsin adopted a mechanism where each additional 
125 MW of capacity saved with energy efficiency yield¬ 
ed an additional 1 percent ROE. Connecticut authorized 
a 1 to 5 percent additional return (Reid, 1988). 


Although a bonus rate of return remains an option 
"on the books" in a number of states, it is seldom 
used, largely because capitalization of efficiency in¬ 
vestments has fallen from favor. The most often-cited 
current example of a bonus return mechanism, and the 
only one applied to a utility with significant efficiency 
spending, is found in Nevada. The Nevada approach, 
described earlier, allows a bonus rate of return for D5M 
that is 5 percent higher than authorized rates of return 
for supply investments. The earlier discussion cited the 
concerns raised by some that this mechanism does not 
provide an incentive for superior performance. 

6.5 Pros and Cons of Utility 
Performance Incentive 
Mechanisms 

Shared savings and performance target incentive 
mechanisms are similar, in that both tie an incentive to 
achievement of some target level of performance. The 
two differ in the specific nature of the target and the 
base upon which the incentive is calculated. The appli¬ 
cation of each mechanism will differ based on regula¬ 
tors' decisions regarding the specific performance target 
levels; the relative share of incentive base available as 
an incentive; the maximum amount of the incentive; 
and whether performance penalties can be imposed (as 
opposed to simply failing to earn a performance incen¬ 
tive). Whether an incentive mechanism is implemented 
will depend on how regulators balance the value of the 
mechanism in incenting exemplary performance against 
the cost to ratepayers and arguments that customers 
should not have to pay for a utility that simply complies 
with statutory or regulatory mandates. A bonus rate of 
return mechanism also can include performance mea¬ 
sures (those applied in the late 1980s and early 1990s 
often did), but may not, as in the Nevada example. 

Table 6-7 summarizes the major pros and cons of per¬ 
formance incentive mechanisms as a whole. 


National Action Plan for Energy Efficiency 


6-11 




Table 6-7. Pros and Cons of Utility Performance Incentive Mechanisms 

Pros 


• Provide positive incentives for utility investment in energy efficiency programs. 

• Policy-makers can influence the types of program investments and the manner in which they are implement¬ 
ed through the design of specific performance features. 


Cons 


• Typically requires post-implementation evaluation, which entails the same issues as cited with respect to fixed- 
cost recovery mechanisms. 

• Mechanisms without performance targets can reward utilities simply for spending, as opposed to realizing 
savings. 

• Mechanisms without penalty provisions send mixed signals regarding the importance of performance. 

• Incentives will raise the total program costs borne by customers and reduce the net benefit that they 
otherwise would capture. 


6.6 Notes 

1. Performance targets can include metrics beyond energy and de¬ 
mand savings; installations of eligible equipment or market share 
achieved for certain products such as those bearing the ENERGY 
STAR™ label. 

2. Department of Telecommunications and Energy on Its Own 
Motion to Establish Methods and Procedures to Evaluate and 
Approve Energy Efficiency Programs, Pursuant to G.L. c. 25, § 

19 and c. 25A, § 11G, found at, <www.mass.gov/Eoca/docs/dte/ 
electric/98-100/finalguidelinesorder.pdf>. 

3. The following is quoted from Investigation by the Department of 
Telecommunications and Energy on its own motion to estab¬ 
lish methods and procedures to evaluate and approve energy 
efficiency programs, pursuant to G.L. c. 25, § 19 and c. 25A, § 

11G, found at <www.mass.gov/Eoca/docs/dte/electric/98-100/ 
finalguidelinesorder.pdf>. 

4. Final Order in D.T.E./D.P.U Docket 06-45, Petition of Boston 
Edison Company, Cambridge Electric Light Company, and Com¬ 
monwealth Electric Company, d/b/a NSTAR Electric, Pursuant to 
G.L. c. 25, § 19 and G.L. c. 25A, § 11G, for Approval of Its 2006 
Energy Efficiency Plan. Found at <www.mass.gov/Eoca/docs/dte/ 
electric/06-45/5807dpuorder.pdf>. 

5. Ibid, page 9. 

6. Ibid, page 10. 

7. Avoided costs are the costs that would otherwise be incurred 
by a utility to serve the load that is avoided due to an energy 


efficiency program. Historically, these costs were determined 
administratively according to specified procedures approved by 
regulators. This is still the predominant approach, although some 
jurisdictions now use wholesale market costs to represent avoided 
costs. This Report will not address the derivation of these costs in 
detail, but note that the level of avoided costs is extremely impor¬ 
tant in determining energy efficiency program cost-effectiveness 
and can be the subject of substantial debate. 

8. Minnesota Statute 216B.241, 2006, found at <www.revisor.leg.sta 
te.mn.us/bin/getpub.php?type=s&year=current&num=216B.241 >. 

9. Order Approving Demand-Side Management Financial Incentive 
Plans, Docket No. E,G-999/CI-98-1759, April 7, 2000, ac¬ 
cessed at <https://www.edockets.state.mn.us/EFiling/ShowFile. 
do?DocNumber=822257>. 

10. Ibid, page 16. 

11. Xcel Energy Compliance Filing 2007 Electric and Gas CIP Incen¬ 
tive Mechanisms, Docket E,G-999/C1-98-1759, February 1, 2007, 
accessed at <https://www.edockets.state.mn.us/EFiling/ShowFile. 
do?DocNumber=3761385>. 

12. PG&E and SDG&E must meet therm, kilowatt-hour, and kilowatt 
goals; SCE must meet kilowatt-hour and kilowatt goals; and 
Southern California Gas faces only a therm goal. 

13. Southern California Gas need only meet the 80 percent minimum 
therm savings threshold to be eligible for an incentive. 

14. The net-to-gross ratio is a measurement of program free ridership. 
Free riders are program participants who would have taken the 
program's intended action, even in the absence of the program. 


6-12 


Aligning Utility Incentives with Investment in Energy Efficiency 








I Emerging Models 



This chapter examines two new models currently being explored to address the basic financial effects 
associated with utility energy efficiency investment. The first model has been proposed as an alternative 
comprehensive cost recovery and performance incentive mechanism. The second represents a fundamen¬ 
tally different approach to funding energy efficiency within a utility resource planning and procurement 
framework. 


7.1 Introduction 

Although the details of the policies and mechanisms de¬ 
scribed above for addressing the three financial effects 
continue to evolve in jurisdictions across the country, 
the basic classes of mechanisms have been understood, 
applied, and debated for more than two decades. Most 
jurisdictions currently considering policies to remove 
financial disincentives to utility investment in energy ef¬ 
ficiency are considering one or more of the mechanisms 
described earlier. However, new models that do not fit 
easily within the traditional classes of mechanisms are 
now being considered. 

7.2 Duke Energy’s Proposed 
Save-a-Watt Model 

The persistent and sometimes acrimonious nature of the 
debate over the proper approach to removing disincen¬ 
tives, combined with a sense that the energy efficiency 
investment environment is on the threshold of funda¬ 
mental change, has led some to search for a new way 
to address the investment disincentive. Although no 
approach has yet been adopted, an intriguing proposal 
has emerged from Duke Energy in an energy efficiency 
proceeding in North Carolina. 1 Duke's energy efficiency 
investment plan includes an energy efficiency rider that 
encapsulates program cost recovery, recovery of lost 
margins, and shareholder incentives into one concep¬ 
tually simple mechanism keyed to the utility's avoided 


cost. The approach is an attempt to improve upon previ¬ 
ous methods with a more streamlined and comprehen¬ 
sive mechanism. 

The energy efficiency rider supporting Duke's proposal 
is based on the notion that if energy efficiency is to be 
viewed from the utility's perspective as equivalent to 
a supply resource, the utility should be compensated 
for its investment in energy efficiency by an amount 
roughly equal to what it would otherwise spend to 
build the new capacity that is to be avoided. Thus, 
the Duke proposal would authorize the company "to 
recover the amortization of and a return on 90% of the 
costs avoided by producing save-a-watts" (Duke Energy, 
2007, p. 2). There is no explicit program cost recovery 
mechanism, no lost margin recovery mechanism and no 
shareholder incentive mechanism—all such costs and 
incentives would be recovered under the 90 percent of 
avoided cost plan. According to Duke, this structure cre¬ 
ates an explicit incentive to design and deliver programs 
efficiently, as doing so will minimize the program costs 
and maximize the financial incentive received by the 
company. This mechanism would apply to the full Duke 
demand-side portfolio, including demand-response 
programs. 

The Duke proposal includes one element that is often 
not addressed explicitly in other cost recovery and in¬ 
centive mechanisms, but has significant implications. A 
number of states have, for a variety of reasons, exclud¬ 
ed demand response from incentive mechanisms. This 
becomes an issue insofar as demand response programs 


National Action Plan for Energy Efficiency 


7-1 


typically cost considerably less on a per-kilowatt basis 
than energy efficiency, and thus could yield substantial 
margins for the company under a cost recovery and 
incentive mechanism that pays on the basis of avoided 
cost. Currently available information on the proposal 
does not provide a basis for evaluating how significant 
an issue this might be (e.g., what portion of the total 
portfolio's impacts is due to demand response programs 
contained therein). 

The proposed rider is to be implemented with a bal¬ 
ancing mechanism, including annual adjustments for 

i 

changes in avoided costs going forward, and to en¬ 
sure that the company is compensated only for actual 
energy and capacity savings as determined by ex post 
evaluation. However, the rider is set initially based on 
the company's estimate of savings, and the company 


acknowledges that meaningful evaluation cannot oc¬ 
cur until implementation has been underway for some 
time. For example, at least one year's worth of program 
data is required to enable valid samples to be drawn. 
Drawing the samples, performing data collection, and 
conducting analysis and report preparation can then 
take another six months or more. Duke's filing suggests 
that true-up results may lag by about three years (Duke 
Energy, 2007, note 4, p. 12). 

The basic mechanics of the energy efficiency rider are 
as follows. The calculations are performed by customer 
class, consistent with many recovery mechanisms that, 
for equity reasons, allocate costs to the classes that ben¬ 
efit directly from the investments. The nomenclature for 
the class allocation has been omitted here for simplicity. 


EEA = (AC + BA) -f sales ■ 

Where: 

EEA = Energy efficiency adjustment, expressed in $/kWh 
AC = Avoided cost revenue requirement 
BA = Balance adjustment (true-up amount) 

AC = (ACC + ACE) x 0.90 

Where: 

ACC = Avoided capacity cost revenue requirement 
AEC = Avoided energy cost revenue requirement 

ACC = DC + (ROE x ACI) summed over each vintage year, measure/program 

Where: 

ACI = Present value of the sum of annual avoided capacity cost (AACT), less depreciation 
DC = Depreciation of the avoided cost investment 
ROE = Weighted return on equity/1 -effective tax rate 

AACT = PD kw x AAC s/kw/year (for each vintage year) 

Where: 

PD = Projected demand impacts for each measure/program by vintage year 
AAC = Annual avoided costs per year, including avoided transmission costs 


7-2 


Aligning Utility Incentives with Investment in Energy Efficiency 







ACE = DE + (ROE x AEI) 

Where: 

DE = Depreciation of the avoided energy investment 

AEI = Present value of the sum of annual avoided energy costs (AAET), less accumulated depreciation 

AAET = PE kwh X AEC s/kwh/year (for each vintage year) 

Where: 

i 

PE = Projected energy impacts by measure/program by year 

AEC = Annual energy avoided costs, calculated as the difference between system energy costs with and without 
the portfolio of energy efficiency programs. 


The mechanism's adjustment factor (BA from the first equation) addresses the true-up and is calculated as follows: 

BA = AREP-RREP 

Where: 

AREP = Actual revenues from the evaluation period collected by the mechanism (90 percent of avoided cost) 
RREP = Revenue requirements for the energy efficiency programs for the same period 

All variables apply to and all calculations are performed over the "evaluation period" which is the time period to 
which the evaluation results apply. 

AREP = EE x AKWH x RREP 

Where: 

EE = The rider charge expressed in cents/kWh 

AKWH = Actual sales for the evaluation period by class 

RREP = 90% x [(ACC x (AD/PD)] + [AEC x (AE/PE)] 

Where: 

ACC = Avoided capacity revenue requirement for the evaluation period 

AD = Actual demand reduction for the period based on evaluation results 

PD = Projected demand reduction for the same period 

AEC = Avoided energy revenue requirement for the period 

AE = Actual energy reduction for the period based on evaluation results 

PE = Projected energy reduction for the period. 


National Action Plan for Energy Efficiency 


7-3 









I 


If evaluated savings (in kilowatt-hours and kilowatts) 
equal planned savings over the relevant period, then 
there is no adjustment. 

Avoided costs are administratively determined in accor¬ 
dance with North Carolina rules, where avoided costs 
(both capacity and energy) are calculated based on the 
peaker methodology and are approved by the North 
Carolina Utilities Commission on a biannual basis (per¬ 
sonal communication with Raiford Smith, Duke Energy, 
May 25, 2007). 

It is important to emphasize that Duke's energy ef¬ 
ficiency rider has only recently been filed as of this 
writing, and the regulatory review has only just begun. 
The proposal clearly represents an innovation in thinking 
regarding elimination of financial disincentives for utili¬ 
ties, and it has intuitive appeal for its conceptual sim¬ 
plicity. The Save-a-Watt rider does represent a distinct 
departure from cost recovery and shareholder incen¬ 
tives convention. In its attempt to address the range of 
financial effects described above in a single mechanism, 
the rider requires a number of detailed calculations, 
and estimating the amount of money to be recovered is 
complicated. 

7.3 ISO New England's Market- 
Based Approach to Energy Effi¬ 
ciency Procurement 

The development of organized wholesale markets that 
allow participation from providers of load reduction cre¬ 
ates both an alternative source of funding for energy ef¬ 
ficiency projects and a source of revenue that potentially 
could be used to provide financial incentives for energy 
efficiency performance. 

ISO New England, New England's electricity system 
operator and wholesale market administrator, is imple¬ 
menting a new capacity market, known as the forward 
capacity market (FCM). The FCM will, for the first 
time, permit all demand resources to participate in the 
wholesale capacity market on a comparable basis with 


traditional generation resources. Demand resources, 
as defined by ISO New England's market rules, include 
energy efficiency, load management, real-time de¬ 
mand response, and distributed generation. An annual 
forward capacity auction would be held to procure 
capacity three years in advance of delivery. This three- 
year window provides developers with sufficient time 
to construct/complete auction-clearing projects and to 
reduce the risk of developing new capacity. All capacity 
providers receive payments during the annual commit¬ 
ment period based upon a single clearing price set in 
the forward capacity auction. In return, the providers 
commit to providing capacity for the duration of the 
commitment period by producing power (if a generator) 
or by reducing demand (if a demand resource) during 
specific performance hours (typically peak load hours 
and shortage hours—hours in which reserves needed 
for reliable system operation are being depleted) 
(Yoshimura, 2007, pp. 1-2). 

This system creates two revenue pathways. First, non¬ 
utility providers of demand reduction, such as energy 
service companies, municipalities, and retail customers 
(perhaps through aggregators), could receive a stream 
of revenues that could help finance incremental energy 
efficiency projects. Second, utilities in the region could 
bid the demand reduction associated with energy ef¬ 
ficiency programs that they are implementing. The rev¬ 
enues received by utilities from winning bids could be 
handled in a variety of ways depending on the policy of 
their state regulators. Traditionally, any revenues earned 
from these programs would be credited against the util¬ 
ities' jurisdictional revenue requirement. This approach 
assumes the programs were funded by ratepayers and 
therefore, that the benefits from these programs should 
accrue to ratepayers. However, several alternatives exist 
to this approach: 2 

• Allow revenues earned from winning bids to be 
retained by the utilities as financial incentives. Rather 
than having ratepayers directly fund a performance 
incentive program, as is typically done, state regula¬ 
tors could allow utilities to retain some or all of the 
funds received from the capacity auction as a reward 


7-4 


Aligning Utility Incentives with Investment in Energy Efficiency 


for performance and inducement to implement effec¬ 
tive programs that reduce system peak load. 

• Require that some or all of the revenues earned be 
applied to the expansion of existing programs or 
development of new programs. 

• Require that the jurisdictional costs of energy efficien¬ 
cy programs be offset by revenues earned from the 
auction, resulting in a rate decrease for jurisdictional 
customers. 

The ISO New England forward capacity auction is in its 
very early stages. The initial "show-of-interest" solicita¬ 
tion produced almost 2,500 MW of additional demand 
reduction potential, of which almost half was in the 
form of some type of energy efficiency. About 80 per¬ 
cent of the capacity was proposed by non-utility entities 
(Yoshimura, 2007, p. 4). 

While this model represents a new source of revenue 
to fund energy efficiency investments, it also presents 
a novel way to capture value from energy efficiency 
programs by virtue of their ability to reduce wholesale 
power costs. Increasing the supply of capacity that is 
bid into the auction, particularly from lower-cost energy 
efficiency, would likely result in a lower market clearing 
price for capacity resources, which would lower overall 
regional capacity costs. 

However, whether this model becomes a significant 
source of revenue to support utility energy efficiency 
programs is not yet known at this time. Successful 


implementation of an FCM that allows energy efficiency 
resources to participate requires that the control area 
responsible for resource adequacy develop rigorous 
and complex rules to ensure that the impacts of energy 
efficiency programs on capability responsibility are real 
and are not double-counted. Additionally, using a re¬ 
gional capacity market to fund energy efficiency results 
in all consumers of electricity within the region paying 
for energy efficiency programs implemented in the 
region. Accordingly, policy-makers in the region must be 
prepared for the potential shifting of energy efficiency 
program cost recovery from jurisdictional ratepayers to 
all ratepayers in the region. State regulatory policy with 
respect to the treatment of revenues earned in whole¬ 
sale markets may or may not provide an incentive for 
utilities to increase the amount of energy efficiency in 
response to these markets. Finally, the model works only 
where there are organized wholesale markets that in¬ 
clude a capacity market. Currently, much of the country 
operates without a capacity market. 

7.4 Notes 

1. The information in this chapter is drawn largely from the Ap¬ 
plication of Duke Energy Carolinas, LLC for Approval of Save-a- 
Watt Approach, Energy Efficiency Rider and Portfolio of Energy 
Efficiency Programs. 

2. Note that these alternatives are not mutually exclusive. 


National Action Plan for Energy Efficiency 


7-5 
















































8 Final Thoughts 
l Getting Started 



This final chapter provides seven lessons for policy makers to consider as they begin the process of better 
aligning utility incentives with investment in energy efficiency. 


8.1 Lessons for Policy-Makers 

The previous four chapters described a variety of op¬ 
tions for addressing the barriers to efficiency investment 
through program cost recovery, lost margin recovery and 
performance incentive mechanisms. Chapter 2 under¬ 
scored the principle that it is the combined effect of cost 
and incentive recovery that matters in the elimination of 
financial disincentives. There is no single optimal solution 
for every utility and jurisdiction. Context matters very 
much, and it is less important that a jurisdiction address 
each financial effect than that it crafts a solution that 
leaves utility earnings at least at pre-energy efficiency 
program implementation levels and perhaps higher. 

The history of utility energy efficiency investment is rich 
with examples of how regulatory commissions and the 
governing bodies of publicly and cooperatively owned 
utilities have explored their cost recovery policy options. 
As these options are reconsidered and reconfigured in 
light of the trend toward higher utility investment in 
energy efficiency, this experience yields several lessons 
with respect to process. 

I 

1. Set cost recovery and incentive policy based 
on the direction of the market's evolution. No 

policy-maker sets a course by looking over his or her 
shoulder. Nevertheless, there is a natural tendency to 
project onto the future what seems most comfortable 
today. The rapid development of technology, the likely 
integration of energy efficiency and demand response, 
the continuing evolution of utility industry structure, 
the likelihood of broader action on climate change, 
and a wide range of other uncertainties argue for cost 
recovery and incentive policies that can work with 
intended effect under a variety of possible futures. 


2 Apply cost recovery mechanisms and utility per¬ 
formance incentives in a broad policy context. 

The policies that affect utility investment in energy 
efficiency are many and varied, and each will control, 
to some extent, the nature of financial incentives and 
disincentives that a utility faces. Policies that could im¬ 
pact the design of cost recovery and incentive mecha¬ 
nisms include those having to do with rate design 
(PBR, dynamic pricing, SFV designs, etc.); non-C0 2 
environmental controls such as NO x cap-and-trade ini¬ 
tiatives; broader clean energy and distributed energy 
development; and the.development of more liquid 
wholesale markets for load reduction programs. 

3. Test prospective policies. Cost recovery and incen¬ 
tive discussions have tended toward the conceptual. 
What is appropriate to award and allow? Is it the 
utilities' responsibility to invest in energy efficiency, 
and do they need to be rewarded for doing so? 
Should revenues be decoupled from sales? All ques¬ 
tions are appropriate and yet at the end of the day, 
the answers tell policy-makers very little about how 
a mechanism will impact rates and earnings. This 
answer can only come from running the numbers— 
test driving the policy—and not simply under the 
standard business-as-usual scenario. Business is never 
"as usual," and a sustainable, durable policy requires 
that it generate acceptable outcomes under unusual 
circumstances. Complex mechanisms that have many 
moving parts cannot easily be understood absent 
simulation of the mechanisms under a wide range 
of conditions. This is particularly true of mechanisms 
that rely on projections of avoided costs, prices, or 
program impacts. 


National Action Plan for Energy Efficiency 


8-1 




4. Policy rules must be clear. Earlier chapters of this 
Report described the relationship between perceived 
financial risk and utility disincentives to invest in en¬ 
ergy efficiency. This risk is mitigated in part by having 
cost recovery and incentive mechanisms in place, but 
the effectiveness of these mechanisms depends very 
much on the rules governing their application. For 
example, review and approval of energy efficiency 
program budgets by regulators prior to implemen¬ 
tation provides utilities with greater assurance of 
subsequent cost recovery. Alternatively, spelling out 
what is considered prudent in terms of planning 
and investment can help allay concerns over post¬ 
implementation disallowances. Similarly, the criteria/ 
methods to be applied when reviewing costs, recov¬ 
ery of lost margins, and claimed incentives should 

be as specific as possible, recognizing the need to 
preserve regulatory flexibility. Where possible, the 
values of key cost recovery and incentive variables, 
such as avoided costs, should be determined in other 
appropriate proceedings, rather than argued in cost 
recovery dockets. Although this clear separation 
of issues will not always be possible, the principal 
focus of cost recovery proceedings should be on (1) 
whether a utility adhered to an approved plan and, 
if not, whether it was prudent in diverging, and (2) 
whether costs and incentives proposed for recovery 
are properly calculated. 

5. Collaboration has value. Like every issue involving 
utility costs of service, recovering the costs associ¬ 
ated with program implementation, recovering lost 
margins/fixed costs, and providing performance 

l 

incentives will involve determinations of who should 
pay how much. These decisions invariably will draw 
active participation from a variety of stakeholders. 
Key among these are utilities, consumer advocates, 
environmental groups, energy efficiency proponents, 
and representatives of large energy consumers. 
Fashioning a cost recovery and incentives policy will 
be challenging. The most successful and sustainable 
cost recovery and incentive policies are those that (1) 
were based on a consultative process that includes 
broad agreement on the general aims of the energy 


efficiency investment policy, and (2) are based on 
legislative enactment of clear regulatory authority to 
implement the policy. 

6. Flexibility is essential. Most of the states that have 
had significant efficiency investment and cost recov¬ 
ery policies in place for more than a few years have 
found compelling reasons to modify these policies 

at some point. Rather than indicating policy incon¬ 
sistency, these changes most often reflect an institu¬ 
tional capacity to acknowledge either weaknesses in 
existing approaches or broader contextual changes 
that render prior approaches ineffective. Minnesota 
developed and subsequently abandoned a lost mar¬ 
gin recovery mechanism after finding that its costs 
were too high, but the state replaced the mechanism 
with a utility performance incentive policy that ap¬ 
pears to be effective in addressing barriers to invest¬ 
ment. California adopted, abandoned, and is now 
set to again adopt performance incentive mecha¬ 
nisms as it responds to broader changes in energy 
market structure and the role of utilities in promoting 
efficiency. Nevada adopted a bonus rate of return for 
utility efficiency investments and is now reconsider¬ 
ing that policy in the context of the state's aggressive 
resource portfolio standard. Policy stability is desir¬ 
able, and changes that suggest significant impacts 
on earnings or prices can be particularly challenging, 
but it is the stability of impact rather than adherence 
to a particular model that is important in addressing 
financial disincentives to invest. 

7. Culture matters. One important test of a cost 
recovery and incentives policy is its impact on cor¬ 
porate culture. A policy providing cost recovery is an 
essential first step in removing financial disincentives 
associated with energy efficiency investment, but it 
will not change a utility's core business model. Earn¬ 
ings are still created by investing in supply-side assets 
and selling more energy. Cost recovery, plus a policy 
enabling recovery of lost margins might make a util¬ 
ity indifferent to selling or saving a kilowatt-hour or 
therm, but still will not make the business case for 
aggressive pursuit of energy efficiency. A full comple- 


8-2 


Aligning Utility Incentives with Investment in Energy Efficiency 


ment of cost recovery, lost margin recovery, and 
performance incentive mechanisms can change this 
model, and likely will be needed to secure sustain¬ 
able funding for energy efficiency at levels necessary 
to fundamentally change resource mix. 

As utility spending on energy efficiency programs rises 
to historic levels, attention increasingly falls on the poli¬ 
cies in place to recover program costs, recover potential 
lost margins, and provide performance incentives. These 
policies take on even greater importance if utilities are 
expected to go beyond current spending mandates 
and adopt investment in customer energy efficiency as 
a fundamental element of their business strategy. The 
financial implications of utility energy efficiency spend¬ 
ing can be significant, and failure to address them 
ensures that at best, utilities will comply with policies 
requiring their involvement in energy efficiency, and 
at worst, it could lead to ineffective programs and lost 
opportunities. 

This paper has outlined the financial implications sur¬ 
rounding utility funding for energy efficiency and the 
mechanisms available for addressing them, with the 


intent of supporting policies that align utility financial 
incentives with investment in cost-effective energy ef¬ 
ficiency. The variety of policy options is testament to 
the creativity of state policy-makers and utilities, but as 
pressure for higher efficiency spending levels increases, 
the volume of the debate surrounding these options 
also increases. To a great extent, the debates revolve 
around the basic tenets of utility regulation. Some effi¬ 
ciency cost recovery, margin recovery, and performance 
incentive mechanisms imply changes in the approach to 
utility regulation and ratemaking. 

Building the consensus necessary to support significant 
increases in utility administration of energy efficiency 
will require that these tenants be revisited. If state and 
federal policy-makers conclude that utilities should play 
an increasingly aggressive role in promoting energy ef¬ 
ficiency, adaptations to these tenants to accommodate 
this role will need to be explored. An important first 
step may be building a common understanding around 
the financial implications of utility spending for efficien¬ 
cy, including development of a consistent cost account¬ 
ing framework and terminology. 


National Action Plan for Energy Efficiency 


8-3 


































Appendix 

A: 


National Action Plan 
for Energy Efficiency 
Leadership Group 




Co-Chairs 


Marsha Smith 
Commissioner, Idaho Public 
Utilities Commission 
President, National Asso¬ 
ciation of Regulatory Utility 
Commissioners 

James E. Rogers 
Chairman, President, and 
C.E.O. 

Duke Energy 

Leadership Group 


Barry Abramson 
Senior Vice President 
Servidyne Systems, LLC 

Tracy Babbidge 
Director, Air Planning 
Connecticut Department of 
Environmental Protection 

Angela S. Beehler 
Director of Energy 
Regulation 

Wal-Mart Stores, Inc. 

Jeff Bladen 

General Manager, Market 
Strategy 

PJM Interconnection 

Sheila Boeckman 
Manager of Business Op¬ 
erations and Development 
Waverly Light and Power 

Bruce Braine 
Vice President, Strategic 
Policy Analysis 
American Electric Power 


Cheryl Buley 
Commissioner 
New York State Public 
Service Commission 

Jeff Burks 

Director of Environmental 

Sustainability 

PNM Resources 

Kateri Callahan 
President 

Alliance to Save Energy 

Jorge Carrasco 
Superintendent 
Seattle City Light 

Lonnie Carter 
President and C.E.O. 
Santee Cooper 

Gary Connett 
Manager of Resource Plan¬ 
ning and Member Services 
Great River Energy 

Larry Downes 
Chairman and C.E.O. 

New Jersey Natural Gas 
(New Jersey Resources 
Corporation) 

Roger Duncan 
Deputy General Manager, 
Distributed Energy Services 
Austin Energy 

Angelo Esposito 
Senior Vice President, Ener¬ 
gy Services and Technology 
New York Power Authority 

Jeanne Fox 
President 

New Jersey Board of Public 
Utilities 


Anne George 
Commissioner 
Connecticut Department 
of Public Utility Control 

Dian Grueneich 
Commissioner 
California Public Utilities 
Commission 

Blair Hamilton 
Policy Director 
Vermont Energy Invest¬ 
ment Corporation 

Leonard Haynes 
Executive Vice President, 
Supply Technologies, 
Renewables, and Demand 
Side Planning 
Southern Company 

Mary Healey 

Consumer Counsel for the 
State of Connecticut 
Connecticut Consumer 
Counsel 

Joe Hoagland 
Vice President, Energy 
Efficiency and Demand 
Response 

Tennessee Valley Authority 

Sandy Hochstetter 
Vice President, Strategic 
Affairs 

Arkansas Electric 
Cooperative Corporation 

Helen Howes 
Vice President, Environ¬ 
ment, Health and Safety 
Exelon 


Bruce Johnson 
Director, Energy 
Management 
Keyspan 

Mary Kenkel 

Consultant, Alliance One 
Duke Energy 

Ruth Kiselewich 
Director, Conservation 
Programs 

Baltimore Gas and Electric 

Rick Leuthauser 
Manager of Energy 
Efficiency 

MidAmerican Energy 
Company 

Harris McDowell 
Senator 

Delaware General Assembly 

Mark McGahey 
Manager 

Tristate Generation 
and Transmission 
Association, Inc. 

Ed Melendreras 

Vice President, Sales and 

Marketing 

Entergy Corporation 

Janine Migden-Ostrander 
Consumers' Counsel 
Office of the Ohio 
Consumers' Counsel 

Michael Moehn 

Vice President, Corporate 

Planning 

Ameren Services 


National Action Plan for Energy Efficiency 


Appendix A-1 




I 


Fred Moore 

Director Manufacturing & 
Technology, Energy 
The Dow Chemical 
Company 

Richard Morgan 

Commissioner 

District of Columbia Public 

Service Commission 

Brock Nicholson 
Deputy Director 
Division of Air Quality 
North Carolina Air Office 

Pat Oshie 
Commissioner 
Washington Utilities and 
Transportation Commission 

Douglas Petitt 
Vice President, 
Government Affairs 
Vectren Corporation 

Bill Prindle 
Deputy Director 
American Council for an 
Energy-Efficient Economy 

Phyllis Reha 
Commissioner 
Minnesota Public Utilities 
Commission 

Roland Risser 

Director, Customer Energy 
Efficiency 

Pacific Gas and Electric 

Gene Rodrigues 
Director, Energy Efficiency 
Southern California Edison 

Art Rosenfeld 
Commissioner 
California Energy 
Commission 

Gina Rye 
Energy Manager 
Food Lion 


Jan Schori 
General Manager 
Sacramento Municipal 
Utility District 

Ted Schultz 
Vice President, 

Energy Efficiency 
Duke Energy 

Larry Shirley 
Division Director 
North Carolina Energy 
Office 

Tim Stout 

Vice President, Energy 
Efficiency 
National Grid 

Deb Sundin 

Director, Business Product 

Marketing 

Xcel Energy 

Paul Suskie 
Chairman 

Arkansas Public Service 
Commission 

Dub Taylor 
Director 

Texas State Energy Conser¬ 
vation Office 

Paul von Paumgartten 
Director, Energy and Envi¬ 
ronmental Affairs 
Johnson Controls 

Brenna Walraven 
Executive Director, Nation¬ 
al Property Management 
USAA Realty Company 

Devra Wang 

Director, California Energy 
Program 

Natural Resources Defense 
Council 

J. Mack Wathen 

Vice President, Regulatory 

Affairs 

Pepco Holdings, Inc. 


Mike Weedall 
Vice President, Energy 
Efficiency 
Bonneville Power 
Administration 

Zac Yanez 
Program Manager 
Puget Sound 

Henry Yoshimura 
Manager, Demand 
Response 

ISO New England Inc. 

Dan Zaweski 
Assistant Vice President 
of Energy Efficiency and 
Distributed Generation 
Long Island Power Authority 

Observers 


Keith Bissell 
Attorney 

Gas Technology Institute 

Rex Boynton 
President 

North American Technician 
Excellence 

James W. (Jay) Brew 
Counsel 

Steel Manufacturers 
Association 

Roger Cooper 
Executive Vice President, 
Policy and Planning 
American Gas Association 

Dan Delurey 
Executive Director 
Demand Response Coordi¬ 
nating Committee 

Reid Detchon 
Executive Director 
Energy Future Coalition 

Roger Fragua 
Deputy Director 
Council of Energy 
Resource Tribes 


Jeff Genzer 
General Counsel 
National Association of 
State Energy Officials 

Donald Gilligan 
President 

National Association of 
Energy Service Companies 

Chuck Gray 
Executive Director 
National Association of 
Regulatory Utility Commis¬ 
sioners 

Steve Hauser 
President 
GridWise Alliance 

William Hederman 
Member, IEEE-USA Energy 
Policy Committee 
Institute of Electrical and 
Electronics Engineers 

Marc Hoffman 
Executive Director 
Consortium for Energy 
Efficiency 

John Holt 
Senior Manager of 
Generation and Fuel 
National Rural Electric 
Cooperative Association 

Eric Hsieh 

Manager of Government 
Relations 

National Electrical Manu¬ 
facturers Association 

Lisa Jacobson 
Executive Director 
Business Council for 
Sustainable Energy 

Kate Marks 

Energy Program Manager 
National Conference of 
State Legislatures 


Appendix A-2 


Aligning Utility Incentives with Investment in Energy Efficiency 



Joseph Mattingly 
Vice President, Secretary 
and General Counsel 
Gas Appliance Manufac¬ 
turers Association 

Kenneth Mentzer 
President and C.E.O. 

North American Insulation 
Manufacturers Association 

Diane Munns 
Executive Director, Retail 
Energy 

Edison Electric Institute 


Michelle New 
Director, Grants and 
Research 

National Association of 
State Energy Officials 

Ellen Petrill 

Director, Public/Private 
Partnerships 
Electric Power Research 
Institute 

Alan Richardson 
President and C.E.O. 
American Public Power 
Association 


Andrew Spahn 
Executive Director 
National Council on 
Electricity Policy 

Rick Tempchin 

Director, Retail Distribution 

Policy 

Edison Electric Institute 

Mark Wolfe 
Executive Director 
Energy Programs 
Consortium 


I 


Facilitators 

U.S. Department of Energy 

U.S. Environmental 
Protection Agency 


National Action Plan for Energy Efficiency 


Appendix A-3 







I 

































Appendix 

B: Glossary 




Decoupling: A mechanism that weakens or eliminates 
the relationship between sales and revenue (or more 
narrowly the revenue collected to cover fixed costs) by 
allowing a utility to adjust rates to recover authorized 
revenues independent of the level of sales. 

Energy efficiency: The use of less energy to provide 
the same or an improved level of service to the energy 
consumer in an economically efficient way. "Energy 
conservation" is a term that has also been used, but it 
has the connotation of doing without in order to save 
energy rather than using less energy to perform the 
same or better function. 

Fixed costs: Expenses incurred by the utility that do not 
change in proportion to the volume of sales within a 
relevant time period. 

Lost margin: The reduction in revenue to cover fixed 
costs, including earnings or profits in the case of 
investor-owned utilities. Similar to lost revenue, but 
concerned only with fixed cost recovery, or with the 
opportunity costs of lost margins that would have been 
added to net income or created a cash buffer in excess 
of that reflected in the last rate case. 

Lost revenue adjustment mechanisms: Mechanisms 
that attempt to estimate the amount of fixed cost or 
margin revenue that is "lost" as a result of reduced 
sales. The estimated lost revenue is then recovered 
through an adjustment to rates. 

Performance-based ratemaking: An alternative to 
traditional return on rate base regulation that attempts 
to forego frequent rate cases by allowing rates or 

revenues to fluctuate as a function of specified utility 

/ 

performance against a set of benchmarks. 


Program cost recovery: Recovery of the direct costs 
associated with program administration (including 
evaluation), implementation, and incentives to program 
participants. 

Shared savings: Mechanisms that give utilities the 
opportunity to share the net benefits from successful 
implementation of energy efficiency programs with 
ratepayers. 

Return on equity: Based on an assessment of the 
financial returns that investors in that utility would ex¬ 
pect to receive, an expectation that is influenced by the 
perceived riskiness of the investment. 

Straight fixed-variable: A rate structure that allocates 
all current fixed costs to a per customer charge that 
does not vary with consumption. 

System benefits charge: A surcharge dictated by stat¬ 
ute that is added to ratepayers' bills to pay for energy 
efficiency programs that may be administered by utilities 
or other entities. 

Throughput incentive: The incentive for utilities to 
promote sales growth that is created when fixed costs 
are recovered through volumetric charges. Many have 
identified the throughput incentive as the primary bar¬ 
rier to aggressive utility investment in energy efficiency. 


National Action Plan for Energy Efficiency 


Appendix B-1 



























'■ 























Appendix Sources for 

C: Policy Status Table 



This appendix provides specific sources by state for the status of energy efficiency cost recovery and 
incentive mechanisms provided in Tables ES-1 and 1-2. 


Table C-1. Policy Status Table 

States 

Sources 

Arizona 

Arizona Corporation Commission, Decision Nos. 67744 and 69662 in docket 

E-01345A-05-0816 

California 

2001 California Public Utilities Code 739.10. D.04-01-048, D.04-03-23, 

D.04-07-022', D.05-03-023, D.04-05-055, D.05-05-055 

Colorado 

House Bill 1037 (2007) authorizes cost recovery and performance incentives for 
both gas and electric utilities 

Connecticut 

2005 Energy Independence Act, Section 21 

District of Columbia 

Code 34-3514 

Florida 

Florida Administrative Code Rule 25-17.015(1) 

Hawaii 

Docket No. 05-0069, Decision and Order No. 23258 

Idaho 

Idaho PUC Case numbers IPC-E-04-15 and IPC-E-06-32 

Illinois 

Illinois Statutes 20-687.606 

Indiana 

Case-by-case 

Iowa 

Iowa Code 2001: Section 476.6; 199 Iowa Administrative Code Chapter 35 

Kentucky 

Kentucky Revised Statute 278.190 

Maine 

Maine Statue Title 35-A 


National Action Plan for Energy Efficiency 


Appendix C-1 
























Table C-1. Policy Status Table (continued) 

States 

Sources 

Massachusetts 

D.T.E. 04-11 Order on 8/19/2004 

Minnesota 

Statutes 2005, 216B.24 1 

Montana 

Montana Code Annotated 69.8.402 

Nevada 

Nevada Administrative Code 704.9523 

New Hampshire 

Order 23-574, 2000. Statues Chapter 374-F:3 

New Jersey 

, 

N.J.S.A. 46:3-60 

New Mexico 

New Mexico Statues Chapter 62-17-6 

New York 

Case 05-M-0900, In the Matter of the System Benefits Charge III, Order Continuing the 
System Benefits Charge (SBC) 

North Carolina 

Order on November 3, 2005 Docket G-21 Sub 461 

Ohio 

Case-by-case 

Oregon 

Order 02-634 

Rhode Island 

Rhode Island Code 39-2-1.2 

Utah 

<www.raponline.org/showpdf.asp?PDF_URL=%22/pubs/irpsurvey/irput2.pdf%22 and 
Questar Order> 

Washington 

Case-by-case 

Wisconsin 

Wisconsin Statute 16.957.4 


Appendix C-2 


Aligning Utility Incentives with Investment in Energy Efficiency 























D: Case Study Detail 


I i y 



This appendix provides additional detail on the Iowa and Florida case studies discussed in this Report. 


D.1 Iowa 

199 Iowa Administrative Code Chapter 35 1 specifies the 
application of the cost recovery rider. 

Energy efficiency cost recovery (ECR) factors, must be 
calculated separately for each customer or group clas¬ 
sification. ECR factors are calculated using the following 
formula: 

ECR factor = ((RAC) + (ADPC x 12) + (ECE) + A)/ASU 
where: 

• The ECR factor is the recovery amount per unit of 
sales over the 12-month recovery period. 

• PAC is the annual amount of previously approved 
costs from earlier ECR proceedings, until the previ¬ 
ously approved costs are fully recovered. 

• ECE is the estimated contemporaneous expenditures 
to be incurred during the 12-month recovery period. 

• "A" is the adjustment factor equal to over-collections 
or under-collections determined in the annual recon¬ 
ciliation, and for adjustments ordered by the board in 
prudence reviews. 

• ASU is the annual sales units estimated for the 
12-month recovery period. 

• ADPC is amortized deferred past cost. It is calculated 
as the levelized monthly payment needed to provide 
a return of and on the utility's deferred past costs 
(DPC). ADPC is calculated as: 

ADPC = DPC [r(1+r)n] [(1+r)n- 1] 


where: 

• DPC is deferred past costs, including carrying charges 
that have not previously been approved for recovery, 
until the deferred past costs are fully recovered. 

• n is the length of the utility's plan in months. 

• r is the applicable monthly rate of return calculated as: 

r = (1 +R) 1/12 -1 or 
r = R/12 if previously approved 

• R is the pretax overall rate of return the board held 

just and reasonable in the utility's most recent general 

rate case involving the same type of utility service. If 

• 

the board has not rendered a decision in an applica¬ 
ble rate case for a utility, the average of the weighted 
average cost rates for each of the capital structure 
components allowed in general rate cases within the 
preceding 24 months for Iowa utilities providing the 
same type of utility service will be used to determine 
the applicable pretax overall rate of return. 

D.2 Florida 

The procedure for conservation cost recovery described 

by Florida Administrative Code Rule 25-17.015(1 ) 2 

includes the following elements: 

• Utilities submit an annual final true-up filing showing 
the actual common costs, individual program costs 
and revenues, and actual total ECCR revenues for the 
most recent 12-month historical period from January 
1 through December 31 that ends prior to the annual 
ECCR proceedings. As part of this filing a utility must 
include: 


National Action Plan for Energy Efficiency 


Appendix D-1 


• A summary comparison of the actual total costs and 
revenues reported, to the estimated total costs and 
revenues previously reported for the same period cov¬ 
ered by the filing. The filing shall also include the final 
over- or under-recovery of total conservation costs for 
the final true-up period. 

- Eight months of actual and four months of pro¬ 
jected common costs, individual program costs, 
and any revenues collected. Actual costs and 
revenues should begin January 1, immediately 
following the period described in paragraph (1) 
(a). The filing shall also include the estimated/ac¬ 
tual over- or under-recovery of total conservation 
costs for the estimated/actual true-up period. 

- An annual projection filing showing 12 months 
of projected common costs and program costs 
for the period beginning January 1, following 
the annual hearing. 

An annual petition setting forth proposed ECCR 
factors to be effective for the 12-month period 
beginning January 1, following the hearing. 

• Within the 90 days that immediately follow the first 
six months of the reporting period, each utility must 
report the actual results for that period. 


• Each utility must establish separate accounts or 
sub-accounts for each conservation program for the 
pgrposes of recording the costs incurred for that 
program. Each utility must also establish separate 
sub-accounts for any revenues derived from specific 
customer charges associated with specific programs. 

• New programs or program modifications must be ap¬ 
proved prior to a utility seeking cost recovery. Specifi¬ 
cally, any incentives or rebates associated with new 
or modified programs may not be recovered if paid 
before approval. However, if a utility incurs prudent 
implementation costs before a new program or 
modification has been approved by the commission, 

a utility may seek recovery of these expenditures. 

Advertising expense recovered through ECCR must be 
directly related to an approved conservation program, 
shall not mention a competing energy source, and shall 
not be company image-enhancing. 

D.3 Notes _ 

1. 199 Iowa Administrative Code Chapter 35, accessed at chttp:// 
www.legis.state.ia.us/Rules/Current/iac/199iac/19935/19935. 
pdf>. 

2. Florida Administrative Code Rule 25-17.015(1), accessed at 
<http://www.flrules.org/gateway/RuleNo.asp?ID=25-17.015>. 


\ 


Appendix D-2 


Aligning Utility Incentives with Investment in Energy Efficiency 


Appendix 


E 


References 



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Round-Up: Decoupling Mechanisms—July 2006 
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Design, July 2006. 

American Gas Association (2006c). Natural Gas Rate 
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American Gas Association (2007). Natural Gas Rate 
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National Action Plan for Energy Efficiency 


Appendix E-1 


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i 

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i 

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Reid, M. (1988). Ratebasing of Utility Conservation and 
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Sedano, R. (2006). Decoupling: Recent Developments 
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Utah Public Service Commission [PSC] (2006). Order 
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Appendix E-2 


Aligning Utility Incentives with Investment in Energy Efficiency 


Yoshimura, H. (2007). Market-Based Approaches to De¬ 
mand Resource Procurement and Pricing: ISO New 
England's Forward Capacity Market. 

E.2 Additional Resources 

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Energy Summit, Panel Discussion. 

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06-004-R, In The Matter of a Notice of Inquiry 
Developing and Implementing Energy Regarding a 
Rulemaking For Efficiency Programs, Initial Com¬ 
ments, March 2006. 

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vice from Energy Newsdata. May 2007. 

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tribution Energy Efficiency Program: Recognizing and 
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establish methods and procedures to evaluate and 
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D.T.E. 03-48 Petition of Boston Edison Company, Cam¬ 
bridge Electric Light Company, and Commonwealth 
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pursuant to G.L. c. 25, § 19 and G.L. c. 25A, § 

11G, for approval by the Department of Telecom¬ 
munications and Energy of an Energy Efficiency Plan 
for 2003. 

D.T.E. 03-2 Joint Petition of Massachusetts Electric Com¬ 
pany and Nantucket Electric Company, pursuant 
to G.L. c. 25, § 19, G.L. c. 25A, § 11G, and G.L. 


c. 164, § 17A, for approval by the Department of 
Telecommunications and Energy of its 2003 Energy 
Efficiency Plan, including a proposal for financial 
assistance to municipal energy efficiency projects, 
September 2003. 

D.T.E./D.P.U. 06-45 Petition of Boston Edison Company, 
Cambridge Electric Light Company, and Common¬ 
wealth Electric Company, d/b/a NSTAR Electric, 
pursuant to G.L. c. 25, § 19 and G.L. c. 25A, § 11G, 
for approval of its 2006 Energy Efficiency Plan, May 
8, 2007. 

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the Incentives. 

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CON-384. 


National Action Plan for Energy Efficiency 


Appendix E-3 


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ies and Good Practice in Rising to the Challenge of 
Liberalization. 

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Distributed Generation Market Assessment: Final 
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and Opportunities Eliminating Disincentives, Cre¬ 
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Mechanisms (Issued and Effective April 20, 2007, 
CASE 03-E-0640—Proceeding on Motion of the 
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Regulatory Assistance Project (2000). Performance- 
Based Regulation for Distribution Utilities. 


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U.S. Kansas Corporation Commission Workshop on 
Energy Efficiency, Regulatory Assistance Project. 

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mittal on Energy Efficiency Panel Discussion on Cost 
Recovery Issues. 

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The Revenue per Customer Method: Presentation to 
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with Demand-Side Resources. Regulatory Assistance 
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Your Incentives Need Alignment? The Third Annual 
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Utah. Regulatory Assistance Project. 

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derstanding & Living with Utility Incentives. EPA Work¬ 
shop on Gas Efficiency. Regulatory Assistance Project. 

Shirley, W. (2007). National Perspective on Cost Effec¬ 
tiveness, Cost Recovery and Financial Incentives. 
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Southern California Edison (2006). Cal.PUC Sheet No. 
41472-E. 

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Incentives: Current Designs and Economic Theory. 
Lawrence Berkeley Laboratory, LBL-36580. 

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Levels and Cost-Effectiveness Testing. Prepared for 
Canadian Association of Members of Public Utility 
Tribunals. 


Appendix E-4 


Aligning Utility Incentives with Investment in Energy Efficiency 


Washington Utilities & Transportation Commission, UTC 
V. Pacificorp D/B/A Pacific Power & Light Company, 
Docket Nos. UE-050684 and UE-050412, Rebuttal 
Testimony of Jim Lazar on Behalf of Public Counsel, 
December 2005 

Weston, R. (2007). Customer-Sited Resources & Utility 
Profits: Aligning Incentives with Public Policy. Regu¬ 
latory Assistance Project. 


i 


National Action Plan for Energy Efficiency 


Appendix E-5 
















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